Fortnightly - Spinninghttp://www.fortnightly.com/tags/spinning
enHybrid Storagehttp://www.fortnightly.com/fortnightly/2010/06/hybrid-storage
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Ultracapacitors and batteries work together to solve power quality problems.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Chad Hall</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Technology Corridor</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Chad Hall</b> (<a href="mailto:chall@ioxus.com">chall@ioxus.com</a>) is the COO of Ioxus Inc. Previously, he spent 14 years with Ioxus’ parent company, Custom Electronics Inc.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 2010</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Power quality was not the important issue it is today when electrical appliances consisted of incandescent bulbs, induction motors and other devices of similar design. None of these items was overly sensitive to voltage sag, voltage swell, momentary interruptions or transients. Maybe a bulb would flicker or a motor would momentarily operate at reduced power; however, with the advent of microcomputers and sophisticated control circuitry, power quality has become important. Recent advances in storage devices such as improved batteries and ultracapacitors have made intermediate storage of electrical energy more practical and cost effective—which in turn helps utilities to deliver high-quality power at the local level.</p>
<p>Unlike most other products, electrical energy isn’t easily stored, so when an unexpected spike in demand occurs, it often leads to a reduction in power quality and manifests in voltage sag, harmonic distortion and variations in frequency. In severe cases, excessive load can cause a low frequency, forcing a generating facility to drop off line. This can put excessive load on other generating facilities, in some cases causing a domino effect and widespread power outage. The lack of efficient storage methods requires utilities to keep a vigilant eye on demand and be prepared to bring reserve facilities into action at a moment’s notice in order to prevent power interruptions.</p>
<p>New storage technologies are helping to make that job easier.</p>
<h4>Power Problems</h4>
<p>Demand changes come in two flavors: long- and short-term. The long-term changes are those that occur at a gradual rate, and are illustrated by the summertime increase in demand that accompanies a period of sultry summer weather resulting in the widespread use of air conditioners. This type of demand increase can be handled by the utility, provided it has sufficient capacity or can buy reserves from a neighboring utility via the grid network. More ubiquitous are short-term increases in demand that result from a sudden change in load that might occur when large machinery is brought online in a manufacturing facility. Indeed, the majority of fluctuations occur for a period of less than two seconds, and such momentary changes in demand represent the biggest headaches for utilities, as they lead to reduced power quality.</p>
<p>Power quality also is affected by aging delivery infrastructure. Transmission lines in many areas are overloaded, leading to higher line and power losses due to reactance created by an ever-increasing inductive load. With the proliferation of electronic devices and electric motors, inductive load is increasing, which in turn requires more and more reactive power to reduce the real power that’s delivered by utilities. This not only reduces profits to operators, but exacerbates the problems associated with the efficient delivery of quality power to the end user.</p>
<p>It would be advantageous for independent system operators (ISO) to have a fully integrated network so that power could be shifted from locations that are separated by great distances. However the present grid isn’t integrated, and trying to use it as if it is integrated presents a problem in terms of power quality. The grid has evolved with no real, long-range plan. As a consequence, the current grid system is a patchwork of transmission lines—which, all things considered, works remarkably well. However, unless the problems affecting the grid are addressed in the short term, the situation will worsen, resulting in more frequent, widespread power outages, reduced power quality and the possibility of equipment damage.</p>
<p>Assuming the power grid will remain somewhat fragile—and not integrated—for the foreseeable future, other methods for improving power quality must be considered. Two methodologies that suggest themselves are to reduce the demands placed on the grid infrastructure and to look at alternatives that allow end users or localities to improve power quality in ways that don’t depend on the grid infrastructure.</p>
<h4>Storage Solutions</h4>
<p>One solution is the installation of a power conditioner. A power conditioner provides an alternating current (AC) signal that doesn’t vary in frequency. One straightforward way to do this is to store the power ahead of the conditioner as direct current (DC) using a bank of capacitors, and then use a DC-to-AC inverter to produce perfect 60-Hz AC. The cost of such a conditioner is driven mostly by the total power required. A second approach uses a ride-through solution. Sufficient power is stored in an ultracapacitor bank. In the event of an interruption, the ride-through power supply carries the load. The cost of this system is driven by the transmission line length needed to provide power to the system.</p>
<p>Other solutions to providing energy storage to electrical utility operators include spinning reserve, pumped-hydro, flywheels and high-pressure air. Spinning reserve is the practice of having a generating station running, but offline, until rising demand requires bringing additional generating capacity on line. Spinning reserve is expensive and inefficient, with power plants idling and burning fuel for long periods of time. The pumped-hydro method allows a utility to produce energy at a relatively constant rate and use periods of low demand to pump water into an elevated holding area; when demand increases, the water can be used to produce hydro electricity by recapturing the gravitational potential energy. The flywheel system uses power during periods of low demand to put energy into flywheels and which energy is recaptured when demand increases. Similarly, in compressed-air energy storage systems, high pressure air is accumulated when demand is low and used to drive a turbine under conditions of increased demand.</p>
<p>Pumped hydro and compressed-air storage can work well in specialized conditions—<i>i.e.,</i> when a large reservoir or underground air storage site is available, and when transmission capacity is sufficient to serve the facility. Flywheel farms show some promise, but high maintenance costs have limited their development to prototype projects.</p>
<p>As technology has advanced, however, a new approach to intermediate storage has emerged, using a parallel combination of batteries and ultracapacitors.</p>
<h4>Dense Energy</h4>
<p>The parallel combination has both high energy density and power density. Ultracapacitors, like all capacitors, have a high power density—<i>i.e.</i>, they can deliver a great deal of current from a small package. What differentiates ultracapacitors from their traditional counterparts, electrolytic capacitors, is their high energy density, allowing them to store a vast amount of energy in a small package.</p>
<p>The capacitors with which most design engineers are familiar have short time constants, which means their voltage cycles quickly, whereas ultracapacitor arrays have time constants between tens of seconds and minutes in length. The large capacitance and extremely low frequency time constants allow ultracapacitors to be used in applications that haven’t been practical or economical for other types of capacitors. Using such capacitor supplies in concert with power electronic techniques brings the design and cost of power conditioning equipment within reach of most volume users of electrical energy. Further, as the sophistication of power conditioners increases, their costs will come down, and such systems probably will become available for a much wider spectrum of power consumers.</p>
<p>Because ultracapacitors have a much lower internal resistance and much faster charge rate than batteries do, they can make a battery-powered system run much more efficiently. An array of ultracapacitor cells in series, coupled to a load in parallel with a storage battery, creates a hybrid power source with higher power and energy density than either device in a stand-alone configuration. By gradually taking on a load, batteries are insulated from high current drains that cause thermal, chemical, and mechanical stresses. And by reducing current spikes, the internal temperature of batteries is decreased substantially, extending the life of the batteries by as much as 400 percent, depending on the application. Additionally, there are times when a battery simply can’t deliver the current needed for an application. In this situation, an ultracapacitor can be used to augment the battery.</p>
<p>The primary limitation associated with ultracapacitors is their low voltage rating, which may be overcome to some extent in lower voltage applications by constructing a parallel-series array of devices; the series connections increase voltage standoff, while the parallel connections increase capacitance and reduce equivalent series resistance (ESR). The arrays can be interconnected easily and allow for capacitor banks that will function well up to intermediate voltage levels (400 to 600 V).</p>
<p>In most instances, it’s necessary to incorporate a controller and appropriate power electronic circuitry to meet specific needs. For example, an array of ultracapacitors can be used as a power source to compensate for power sags of short duration; however such systems require, in addition to the capacitor bank, a controller and power electronic circuitry to make them really useful. With these additions, a module can be constructed to compensate for power sag and do real-time power factor correction for loads of various sizes. The cost-to-benefit ratio of such a system is at present questionable, but as prices of ultracapacitors decline, such applications will become widespread. These systems also have the ability to be scaled up to higher voltage levels. Experimental applications at grid level still are being evaluated.</p>
<p>Ultracapacitors allow design engineers to separate energy and power needs. In most applications there’s a continuous power demand that’s handled by a primary energy source, and at times, there are peak power demands that require additional capacity. Engineers either cansize the batteries to handle peak demands, or use ultracapacitors to bridge the demand, which has the added benefit of being able to size the primary energy source.</p>
<p>Combinations of ultracapacitors and batteries in energy storage systems can reduce the size, weight and the number of batteries in a system. Such hybridized systems are more efficient and use fewer expensive materials. They also can extend the cycle life of the battery component, which makes the whole system greener.</p>
<p>Hybrid power sources consisting of batteries and ultracapacitors are being used in low- and intermediate-voltage applications. Because these systems are scalable, they have potential for use at high-voltage levels when augmented with the appropriate power electronic circuitry. In order for there to be a burgeoning of the ultracapacitor market, manufacturers will have to increase energy density further, which will make the devices more attractive from both a cost and size point of view. A number of companies are working on this problem, and preliminary research suggests energy densities of ultracapacitors have the potential to exceed the energy densities of many battery types. Some estimates suggest energy densities could be increased by as much as a factor of 100, which would allow for the wholesale replacement of batteries in many applications. Even a modest increase in energy density has the potential for replacing lead-acid storage batteries with ultracapacitors.</p>
<p>The future for ultracapacitors looks bright. If the energy densities and voltage level issues can be overcome at an economical price point, their usefulness in ensuring power quality will increase by orders of magnitude.</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/renewables-solar-11505">Solar</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/transmission">Transmission</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/technology-corridor">Technology Corridor</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1006/images/1006-cvr.jpg" width="1121" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
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<a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/flywheel">Flywheel</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/spinning">Spinning</a><span class="pur_comma">, </span><a href="/tags/spinning-reserve">spinning reserve</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Tue, 01 Jun 2010 04:00:00 +0000puradmin14221 at http://www.fortnightly.comConquering Timehttp://www.fortnightly.com/fortnightly/2008/10/conquering-time
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Understanding the value of pumped storage.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Mark Griffith</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Power Measurements</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Mark Griffith</b> is a senior vice president<i> </i>at Ventyx Energy and leader of its asset<i> </i>valuation practice. He can be reached<i> </i>at <a href="mailto:Mark.R.Griffith@Ventyx.com">Mark.R.Griffith@Ventyx.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - October 2008</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0810/images/0810-PWR-fig1.jpg" width="1379" height="889" alt="" title="Figure 1" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/0810/images/0810-PWR-fig2.jpg" width="1371" height="1283" alt="" title="Figure 2" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0810/images/0810-PWR-fig3.jpg" width="1364" height="1031" alt="" title="Figure 3" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>The key value driver for electric power is time; that is, the exact clock time at which it is produced. Time determines the demand for electricity, the resources competing to supply the power and the state of congestion in the delivery system.</p>
<p>Benjamin Franklin once said that “lost time is never found again.” While there is much truth to this, the time value of electric energy can, in a way, be deferred and “found again” by storing energy in some form and then retrieving it later.</p>
<p>This is the key factor in understanding the value of energy storage. Storage allows one to conquer time, as it were, and deliver power when it is needed, not just when it is generated.</p>
<p>Various schemes exist to store energy, with the most common being chemical energy (<i>e.g.,</i> batteries) and hydroelectric pumped storage. The concept of pumped storage is deceptively simple. When its value is low during off-peak periods, electricity is used to pump water from a lower reservoir to a higher reservoir<i> (see Figure 1)</i>. Later, when the value of the electricity is much greater (on-peak periods), the water is allowed to flow from the upper to lower reservoir, and this movement is used to generate electricity. The pump and generator often constitute the same device, just operating in an opposite direction. Either reservoir can be a natural body of water or a man-made lake.</p>
<p>While pumped-storage projects have been difficult to develop in the past, their economics are improving along with increasing market demand for ancillary services and standby capacity.</p>
<h4>Storage Economics</h4>
<p>Capital costs for pumped-storage plants vary widely according to local conditions (<i>e.g.,</i> is there a pre-existing lake?) and economies of scale, and easily can exceed $2,000/kW. While there is no “fuel” as such, the cost of the output energy depends on the cost of the input energy. The total consumption of energy during the cycle of pumping and generating is called the “round-trip efficiency” and is typically in the range of 70 to 75 percent;<sup></sup>that is, 25 to 30 percent of the input energy is consumed by the storage facility. For example, if the “round trip” efficiency is 70 percent, then 1 MWh off-peak = 0.70 MWh on-peak, or 1.43 MWh off-peak = 1 MWh on-peak.</p>
<p>The round-trip efficiency therefore defines the difference—the spread—between off-peak and on-peak prices needed to dispatch economically a pumped-storage facility. For example, focusing on one month in PJM East—September 2005—average on-peak prices were $122.53/MWh, and average off-peak prices were $59.41/MWh.<i> </i>At an assumed 70 percent efficiency,<i> </i>the margin for a pumped-storage asset was [122.53 - (59.41 x 1.43)], or $37.57/MWh <i>(see Figure 2)</i>.</p>
<p>While this example explains what drives the energy value of pumped storage, those who actually operate such assets likely would cringe at this over-simplification. In a real-time operating environment, pumped-storage calculations constitute very complex problems in optionality, with many complicated and uncertain factors to consider. For example, no one knows with any certainty what power prices will be in the next hour, day or week, so all decisions to pump and generate have market risks associated with them. Additionally, there are many physical limitations to consider, such as the hourly rate at which the plant can pump or generate, the minimum and maximum allowed elevations for the reservoirs, and, in some cases, issues of water requirements for irrigation or fisheries management can come into play.</p>
<h4>More Revenue Sources</h4>
<p>Pumped storage makes energy available on a dispatchable basis during peak-load conditions, and that generating capacity counts toward a load-serving entity’s capacity responsibility in whatever power pool or independent system operator (ISO) it is operating in. If the asset is located in an ISO with a functioning administrative capacity market (as currently exists in New York, New England and PJM), then it will qualify for that ISO’s form of ICAP (installed capacity) payments. In other markets the pumped-storage asset will be able to compete with other generation technologies for capacity payments in bilateral contracts. And in the context of the vertically integrated utility business model, pumped storage is one of many competing technologies to consider in the integrated resource-planning process.</p>
<p>Revenue from capacity payments can make up a significant portion of the total value of a pumped-storage plant. Another significant revenue source can come from payments for ancillary services. The power system requires ancillary services (AS) to provide short-term balancing between load and generation. Without careful balancing, grid frequency and voltage can become unstable, and the entire transmission system risks collapse. Various forms of AS have been developed to reflect that having a quicker response to correct imbalances has greater value to the system, and therefore will generate higher payments. The classic division of AS products follows this pattern:</p>
<p><i>• </i><b>Regulation.</b> This is a “real-time” service that moves generation via automatic generation controls. It is often further divided into “regulation up” and “regulation down,” reflecting that the need to regulate generation in a certain direction tends to depend on the time of day.</p>
<p><i>• </i><b>Spinning Reserves.</b> Typically, these resources need to respond to imbalances within 10 minutes.</p>
<p><i>• </i><b>Non-spinning Reserves.</b> These resources are off-line, but can be started and respond to imbalances within 10 minutes.</p>
<p><i>• </i><b>Replacement Reserves.</b> These resources are off-line, but can be started and respond to imbalances within 60 minutes.</p>
<p><i>• </i><b>Voltage support (VARs) and black-start capability.</b> While needed to operate a transmission system, generators that provide such services generally aren’t compensated for them in wholesale power markets.</p>
<p>There’s a temporal relationship between the various AS markets <i>(see Figure 3)</i>. Using the California ISO as an example, one can see that the value<i> </i>of AS varies dramatically by time of day, and services with quicker response<i> </i>obligations carry higher values. Also,<i> </i>the price levels of the services are quite high, representing a significant potential revenue stream.</p>
<p>Pumped-storage assets are in an excellent position to participate in AS markets. Since there is no “warm-up” period in the starting process, pumped-storage units start quickly and qualify as spinning-reserve services. Pumped-storage units also have very fast ramp rates, and can qualify to provide regulation-up and regulation-down services, potentially in both pumping and generating modes, depending upon their specific designs.</p>
<p>Pumped-storage assets do run the risk of becoming a dominant force in their regional AS markets. For example, in a 50,000-MW peak-demand market, the maximum amount of operating reserves needed (spinning plus non-spinning) may be only 3,000 MW (based on a 6 percent operating reserve criterion). A 1,000-MW pumped-storage facility potentially could provide one-third or more of that market’s operating reserves. This creates an issue where the full capability of the asset materially could impact AS prices, so the asset owner would need to develop a dynamic bidding strategy for optimizing revenue from its joint participation in the energy and AS markets.</p>
<p>While it sounds innocuous at first, each ISO sets its own standards for AS product definition, accreditation standards and market-price formation. The whole concept of administratively designed, competitive AS markets is relatively new and is continuing to evolve, making the pumped-storage owner subject to various administrative risks related to future rule changes. Similar administrative risks exist in the ICAP markets.</p>
<h4>Wind Integration</h4>
<p>Pumped storage offers significant value for integrating storage with variable generation sources, including wind and solar power. Renewable portfolio standards established in many states are leading grid operators to become concerned about their ability to integrate wind resources into the balance of the power-delivery system. Wind generation is variable and non-dispatchable, and if no remedial action is taken, this can lead to unstable grid conditions.</p>
<p>Beyond the grid-operations issues, wind-asset owners suffer because wind generation often occurs during lower load periods, when energy prices are lower, thereby reducing their energy revenues. Asset owners also have seen conditions, such as those in West Texas, where the amount of wind generation has led to curtailed output and reduced (or even negative) energy prices, and has resulted in the need for significant new transmission investments.</p>
<p>Storage technologies offer an intriguing answer to address these concerns. A small localized storage technology (such as batteries) could be located at a wind turbine site and be used to transform the time pattern of the generation before it hits the grid. Pumped storage is a more land-intensive alternative and therefore typically would connect at the grid separately from a wind farm. As a result, the variable nature of the wind resource still might require a local transmission investment to avoid negative grid impacts.</p>
<p>That said, pumped storage could provide grid regulation to offset wind-generation variability. It could store energy during lower value periods, prevent wind curtailment and avoid new transmission investments. Pumped-storage capacity could even shape prices by optimizing schedules of wind output and storage.</p>
<p>This last item is particularly noteworthy because—as in the context of ancillary services—a pumped-storage plant commercially integrated with a wind farm could be used to reduce downward pressure on off-peak prices. So in addition to just realizing value for the off-peak, on-peak spread, storage potentially can change the off-peak prices, benefiting other generation assets in a larger portfolio.</p>
<p>But all these benefits come at some cost. Now, instead of just looking at the capital cost for a wind project, the developer of the combined wind-pumped storage complex faces a much higher initial investment. And, as much as a developer might try, one never can avoid the round-trip efficiency issues.</p>
<h4>Valuing Storage</h4>
<p>Several major value drivers (positive and negative) affect the prospects for building new pumped-storage assets in U.S. markets. The on-peak, off-peak spread is the single biggest value driver. Regional resource scarcity and energy-price volatility typically will improve value. Likewise, market conditions that reduce the price spread by suppressing on-peak prices, such as reduced natural gas prices or high planning-reserve margins, will damage the value of pumped-storage assets.</p>
<p>Operational flexibility is another major value driver. Rapid starting and high ramp rates make it possible to sell various ancillary services. And the ability to move power from off-peak to on-peak periods will allow the asset to generate capacity payments.</p>
<p>Additionally, the potential to integrate with, and increase the value of, wind generation could be a win-win marriage—with the caveat of associated capital costs.</p>
<p>Finally, while pumped storage is ideally suited to provide ancillary services, AS markets easily can become oversupplied. The demand for AS is only a small fraction of the demand for energy, making this revenue stream risky as a primary driver for pumped-storage plants.</p>
<p>Finally, pumped-storage projects continue to face the same operational challenges that have constrained their development in the past. Depending on the site, a pumped-storage project that makes perfect sense for economic reasons might be a non-starter because of environmental opposition, fisheries management regulation or the irrigation needs of the region. Nevertheless, with power capacity and ancillary services becoming more valuable in organized markets—and with a growing fleet of wind turbines—pumped storage does merit new consideration in the U.S. power supply mix.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Valuing Energy, Capacity and Ancillary Services</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>The valuation of any generation asset, including pumped storage, usually is performed using an income-based approach, which in turn requires the use of forecasted values for the prices of energy, capacity and ancillary services. What’s important to understand is how the forecast was prepared, to ensure that the forecast is used in an appropriate context, and that nothing is either “double counted” or “left on the table.”</p><p><b>Energy Prices:</b> The core of the forecast is the energy prices, typically prepared using a market-simulation model. Key questions to address:</p><p>• Does the energy forecast assume all market participants bid at variable costs, or does it include some element of scarcity pricing?<br />• Is the energy forecast meant to represent forward prices or future spot market prices?<br />• Do forward markets influence the near-term results in any way?</p><p><b>Capacity Prices:</b> Typically, the capacity-price forecast relates to the energy-price forecast, looking at the revenue shortfall of some proxy unit. Key questions:</p><p>• Is the capacity forecast meant to be the same as future ICAP prices in markets with ICAP mechanisms?<br />• What proxy unit is used for comparison? Are revenue shortfalls the same for other likely new-entrant technologies?</p><p><b>Ancillary Services Prices:</b> It’s possible to develop either statistical models or structural models to forecast ancillary services (AS) prices. Key questions:</p><p>• Is the capacity market price forecast already designed to capture AS value?<br />• Each ISO has its own approach to AS market design. How does the forecast model capture the specific ISO AS market design?</p><p>A rigorous approach to valuation will help avoid double counting of AS and energy<i> </i>revenues.–<span><span class="bolditalic">MG</span></span></p></div></div></div> </div>
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</div></div></div></div></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/power-measurements">Power Measurements</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0810/images/0810-cover.jpg" width="1121" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
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<a href="/tags/cap">CAP</a><span class="pur_comma">, </span><a href="/tags/economics">Economics</a><span class="pur_comma">, </span><a href="/tags/integration">Integration</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/non-spinning">Non-spinning</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/regulation">Regulation</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/renewable-portfolio-standard">Renewable portfolio standard</a><span class="pur_comma">, </span><a href="/tags/renewable-portfolio-standards">Renewable portfolio standards</a><span class="pur_comma">, </span><a href="/tags/spinning">Spinning</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/storage-technologies">Storage technologies</a><span class="pur_comma">, </span><a href="/tags/voltage-support">Voltage support</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a> </div>
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Wed, 01 Oct 2008 04:00:00 +0000puradmin13781 at http://www.fortnightly.comOptimizing Demand Responsehttp://www.fortnightly.com/fortnightly/2008/05/optimizing-demand-response
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>A comprehensive DR business case quantifies a full range of concurrent benefits.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Eric C. Woychik</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Dr. Woychik</b> is vice president, regulatory affairs for Comverge Inc.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 2008</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0805/images/0805-FEA2-table1.jpg" width="2055" height="845" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/0805/images/0805-FEA2-table-2.jpg" width="1355" height="1117" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Electricity load-serving entities (LSEs) face rapid peak demand growth, skyrocketing expansion costs, mounting risks with electricity resource siting, and unprecedented environmental constraints. As a result, the regulatory metric for resource selection has become least-cost, least-risk.</p>
<p>In this context, utilities and regulators increasingly are attracted to the benefits and market potential of new demand-response (DR) capabilities.</p>
<p>DR offers operational flexibility, and emerging third-party DR contracts minimize risks to LSEs and their customers. But after 25 years of using standard practices to evaluate DR’s cost-effectiveness, the primary DR benefits remain poorly defined.<sup></sup>In most analysis to date, some of DR’s most important wholesale and retail benefits have been given short shrift, or ignored completely. For example, the reduction in region-wide prices from the use of DR rarely is quantified or included at all.</p>
<p>It is well accepted that fast, dispatchable DR can avoid the capital and operating costs of peaking-power capacity such as combustion turbines (CT). Increasingly DR also is demonstrating its ability to avoid capital costs and energy losses related to transmission and distribution. DR resources can be offered and traded in capacity markets, and scheduled by an ISO/RTO to avoid operating reserves, short-term energy, and congestion costs.</p>
<p>DR offers a range of business-case benefits. High-value DR can avoid the need for incremental generation, transmission and distribution capacity, while providing environmental mitigation, reducing prices, helping to mitigate market power, and providing additional option value for market participants.</p>
<p>The challenge is to demonstrate how DR can be used to concurrently capture as many high-value benefits as possible. Optimizing DR capabilities to target the highest and best uses will allow utilities and their customers to achieve maximum value and net concurrent benefits.</p>
<h4>Demand-Response Continuum</h4>
<p>DR reduces electricity use with a spectrum of technologies ranging from simple manual controls to automated digital systems. Dispatchable DR can harness direct load-control (DLC) devices, load-management controls, smart thermostats, advanced metering infrastructure (AMI), and digital energy management systems (EMS). Digital controls can cycle and curtail discretionary loads (lights, motor drives, HVAC systems, <i>etc.</i>) and automatically be triggered by price or reliability.</p>
<p>A continuum of DR services illustrates its relative value in comparison to the supply-side capital and operating costs it can avoid. The ability of DR to reduce supply-side costs is largely a function of the following:</p>
<p>• The specific changes in load shape that result from DR;<br />• The long-term certainty (predictability) of DR over time;<br />• The short-term reliability of DR over time—<i>i.e.</i>, the equivalent of planned and forced outage rates;<br />• The response rate of DR—<i>i.e.</i>, the ramp-rate or load-shift rate; and<br />• The type of supply-side resources avoided and the subsequent costs reduced.</p>
<p>The ability to avoid supply-side capital cost is directly related to the certainty and predictability of the DR, its availability, and the speed of the DR response. DR that is highly certain and in place for a predictable time has the potential to avoid major supply-side capital costs. In the short-term, neither voluntary price response nor voluntary curtailment can avoid capital-cost additions, because neither are certain enough for planning purposes. The speed of DR in terms of response time must be comparable to the generation that it is credited with avoiding. Generation response is defined by ramp-rate—the ability to change power output in megawatts per minute. DR that responds as fast as a combustion turbine can qualify to avoid a CT. Moreover, DR that responds in an hour is much less valuable than either DR or a CT that responds in 10 minutes or less.</p>
<p>The short-term certainty of DR—reliability of operation—can be directly compared to the supply-side measure of forced-outage-rate (FOR), which indicates the expected frequency with which it will fail in use. A related measure is the planned-outage-rate (POR), defined as the portion of time the resource is unavailable, for such reasons as planned maintenance. In combination, FOR and POR reflect the amount of time a resource is forecast to be unavailable. DR can be directly compared to supply-side resources in terms of FOR and POR. The track record of some DR shows a low FOR and a POR of almost zero. This demonstrates that some DR resources are more than comparable to a CT, while other DR resources are inferior in terms of reliability.</p>
<p>Often DR is defined as either price response or reliability response. Going beyond this, a DR value continuum is based on two technology categories, dispatchable DR and voluntary DR <i>(see Table 1)</i>. Higher-value DR can avoid significant long-term capital costs and variable costs. Low-value DR only can reduce short-run variable costs.</p>
<p>Greater value can be captured by DR resources that tap concurrent DR services. The highest value DR concurrently can provide major benefits from all seven benefit categories, including: <b>1</b>) generation capacity and energy/congestion; <b>2</b>) transmission capacity and losses; <b>3</b>) distribution capacity and losses; <b>4</b>) environmental benefits; <b>5</b>) lower market prices for capacity and energy;<sup>2</sup><b>6</b>) market mitigation (price volatility and market power); and <b>7</b>) option value to hedge risks and provide insurance.</p>
<p>Communications and controls are essential to leverage high-value DR technology. New AMI can leverage DR technology to provide greater certainty of DR control and to communicate results, which then allows the utility to harness concurrent benefits. Additionally, other direct consumer benefits allow utilities and regulators to address a range of customer concerns, including the ability to better control their utility bills, energy consumption and carbon footprint.</p>
<p>A critical question to answer is which specific services can a DR resource concurrently provide, to avoid the need for specific supply-side resources? DR resources that provide a larger portfolio of services obviously provide greater value.</p>
<h4>Avoided Generation</h4>
<p>DR’s primary benefits arise from its ability to reduce or avoid generation resources, both in terms of fixed capital costs and variable energy costs.</p>
<p>Avoided variable costs include fuel, line and transformer losses, and variable O&amp;M—the energy components of electricity costs. Both firm and non-firm DR resources properly can be credited with reducing specific variable costs.</p>
<p>In order for DR to be credited with avoiding supply-side capital cost it must avoid load equally or better than a comparable supply-side resource (proxy) would serve load if the DR weren’t available. It must respond operationally as quickly as, or quicker than, the supply-side proxy. It also must be equivalent or better in terms of certainty and predictability, and must exhibit a ramp-rate that is equal or better than the supply-side resource. Finally, it must have comparable or higher short-term reliability (in terms of FOR and POR) than the supply-side resource.</p>
<p>DR’s value for avoiding supply-side capital costs depends on the resource it’s displacing. A critical distinction in power markets is the difference between firm power and non-firm power. Firm power is backed up by operating reserves (spinning reserves and non-spinning reserves), while non-firm power is not.</p>
<p>Avoided firm resources should account for, and sum up, all related capital costs and variable costs. Non-firm DR such as voluntary DR or voluntary price response is less certain, as it lacks the obligation to perform when a contingency occurs, such as a forced outage in generation or transmission. During repeated days of a heat-storm, voluntary price response becomes less reliable, because customer response to price declines as summer heat increases. DLC, on the other hand, performs as a firm resource with certainty and predictability, and thus can avoid the construction of dedicated supply-side resources.</p>
<h4>Assessing Reliability</h4>
<p>For DR to avoid a supply-side resource it must be needed for system reliability, or it must be more cost-effective than the replacement resource. In either case, the reliability of the DR resource must equal or exceed that of the supply resource it’s displacing.</p>
<p>The need for long-run capacity may be based on LSE requirements to satisfy planning-reserve criteria, which usually are set by states. An alternative to planning-reserve criteria is regional or local resource adequacy (RA). RA better defines specific reliability requirements, including ramp rate and availability during specific hours and in specific locations.</p>
<p>Separately, operating-reserve (OR) requirements are defined in each region to ensure short-run reliability. OR includes at least non-spinning reserves (or cold reserves) and spinning reserves (hot reserves). Non-spinning and spinning reserves must be available on a timely basis under specific notice provisions and at pre-specified capacity levels. Thus, the ability of DR to qualify as OR capacity depends on its responsiveness and speed as well as its communications system.</p>
<p>DR can provide dispatchable ramping capacity that displaces older, less efficient, more polluting resources, and enables integration of renewable resources (<i>e.g.</i>, solar and wind resources).<sup></sup> The use of long-term dispatchable DR contracts to provide non-spinning reserve is accepted by the Western Electric Coordinating Council (WECC). Other DR features, such as verifiability, may needed to meet OR requirements.<sup></sup> PacifiCorp uses 90 MWs of residential and commercial DR on the Wasatch Front transmission constraint (the Cool Keeper resource) to satisfy WECC requirements for Non-Spinning Reserve.<sup></sup> Adding value, RA and OR criteria can be simultaneously satisfied by dispatchable DR that provides ramping capacity with certainty to meet system or local peak needs. Generally, this requires a loss-of-load-probability or loss-of-load-expectation analysis.</p>
<p>Dispatchable DR can operate during transmission or distribution contingencies to reduce peak loads on equipment and increase reliability. In these settings, DR preserves reliability and lowers equipment replacement and maintenance costs. At specific grid locations, DR can reduce the need for reactive power and reliability-must-run plants, both related to shortages in T&amp;D or local generation capacity. Accordingly, long-term dispatchable DR can avoid the need for new transmission and at the same time meet RA and OR requirements.</p>
<p>In a recent California settlement on cost-effectiveness, major benefits are attributed to DR that avoids the cost of transmission and distribution.<sup></sup> DR benefits are particularly notable when they reduce T&amp;D capacity requirements in load-growth areas. Avoided T&amp;D benefits are attributable to DR resources that meet “right place” and “right certainty” criteria. These criteria are used to ensure DR is targeted to avoid specific T&amp;D costs, namely: <b>1</b>) in load growth areas where construction of new electricity infrastructure is required but for DR; <b>2</b>) where specific DR resource increase power-delivery capacity; <b>3</b>) where DR can provide certainty of long-term load reduction and little risk of after-the-fact retrofit/replacement; and <b>4</b>) where DR is relied on to reduce local T&amp;D equipment loads.</p>
<p>The track record for dispatchable DR shows that it produces a significant energy-efficiency effect.<sup></sup> DR applied to residential air-conditioning might cause building temperatures to increase slightly, but the reduced on-peak energy use usually is greater than the increased shoulder-peak energy use (during the snap-back period). This energy efficiency effect generally results in less NOx, SOx, and greenhouse gases (GHG).</p>
<h4>Market Benefits</h4>
<p>DR dispatched to meet reliability needs results in reduced capacity and energy costs and might yield congestion benefits. Areas with high local electricity costs can benefit substantially from DR, particularly if wholesale price caps are relaxed and prices reflect load-pocket and regional constraints without significant averaging. Hence, DR can be an excellent hedge against high local capacity, energy, and congestion costs.</p>
<p>LSEs in most ISOs/RTOs rely on out-of-market (OOM) power–that is, power imported from outside the market—during emergencies. As markets increasingly apply scarcity pricing to reflect super-peak market energy needs (<i>e.g.</i>, in ERCOT and CAISO), dispatchable DR can be delivered in OOM and scarcity pricing markets to provide additional benefits.</p>
<p>ISOs and RTOs have aimed to dispatch all DR before requests for OOM or scarcity pricing occur. But this stops DR from participating in these markets on comparable terms with generators. This suggests that revising ISO/RTO policies would enable DR providers to participate directly in OOM and scarcity-pricing transactions.</p>
<p>DR’s use is limited in most jurisdictions to an option contract to provide electrical capacity under emergency conditions. The full option value of DR, however, does not reflect its value as a hedge, particularly to reduce capital costs, fuel risk, price risk, counter-party risk, and to ensure sufficient fast ramping capacity given the increasing use of renewable resources.</p>
<p>DR has additional benefits because it is rolled out incrementally and can be used flexibly on a locational basis. Ideally, dispatchable DR would be traded as a standard financial product. To capture option value, a DR trader must be capable of maximizing its value, which requires sophisticated management.</p>
<p>Most DR resources have characteristics similar to a limited hydropower resource, which uses a finite quantity of water each season and thus might best serve peak capacity needs. Optimizing its use is a challenge. Likewise, most DR is constrained by the number of hours and the specific times when it is available. This suggests DR’s value depends on optimizing its use for several key purposes:</p>
<p>• Meeting planning reserve margin (15 to 17 percent) or resource adequacy needs;<br />• Reducing super-peak prices and obtaining congestion benefits, directly or through congestion revenue rights (CRR) contracts;<br />• Displacing non-spinning or spinning reserves;<br />• Avoiding T&amp;D capital and operating costs on specific circuits;<br />• Reducing emissions of NOx, SOx and GHG;<br />• Serving scarcity pricing or market-purchases at super-peak periods; and<br />• Exploiting the option value of load reduction.</p>
<p>Many of these value streams can be captured during normal DR operations with proper triggers and without double-dipping. A dispatchable DR resource concurrently can provide local resource adequacy, non-spinning reserves, and T&amp;D avoidance, and then be dispatched to provide energy and congestion benefits, reduce grid losses, and lower NOx, SOx and GHG emissions. Of course, ISO/RTO rules must be observed to preclude false trading and to ensure committed resources remain available when called.</p>
<h4>Concurrent Benefits</h4>
<p>Today, DR is used largely as an emergency interruptible resource of value only after dispatch of all supply-side resources. This practice has constrained the role DR can play. Before DR can achieve its full potential as a cost-effective resource, a number of other impediments must be overcome, in both wholesale and retail markets. Most notably, supply-side and DR resources need to be valued on an equivalent basis. For example, in most wholesale markets, DR is credited with resource adequacy, but not with operating reserve benefits. A comparable CT, however, is credited with both.</p>
<p>To make a fair business case for DR, it should be compared directly with generation, transmission, and distribution resources. High-value DR captures a set of concurrent benefits, particularly when its use is optimized. Beyond this, DR coupled with AMI uses digital control and communications to produce higher-value services. Thus, next steps are to define the combined business case for DR plus AMI and energy efficiency resources. These combined resources will capture even greater concurrent benefits, allowing utilities to make the most rational and economical use of America’s energy resources.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. See for example, C. Danforth and E. Woychik, <i>Standard Practice for Cost-Benefit Analysis of Conservation and Load Management Programs</i>, Joint Report of the California Public Utilities Commission and the California Energy Commission, February 1983.</p>
<p>2. See, Brattle Group, <i>Quantifying Demand Response Benefits in PJM</i>, PJM Interconnection and MADRI, Jan. 29, 2007; and Faruqui A., “<a href="http://www.fortnightly.com/fortnightly/2007/03/demand-response-breaking-out-bubble">Breaking Out of the Bubble: Using Demand Response to Mitigate Rate Shocks</a>,” <i>Public Utilities Fortnightly</i>, March 2007.</p>
<p>3. See, <i>e.g.</i>, California Public Utilities Commission Decision 07-12-052 (20 December 2007) on <i>Long-Term Power Procurement</i>.</p>
<p>4. See, CAISO <i>Demand Response Resource Users Guide: Version 3.0</i>. This explains how DR can qualify as Participating Load to directly provide Operating Reserve including Non-Spinning Reserve.</p>
<p>5. J. Bumgarner, <i>Smart Energy Today: The Right Tools for the Job</i>, PacifiCorp Energy, 2007.</p>
<p>6. Comments of Large Energy Consumers Association, Comverge, Inc., Division of Ratepayer Advocates, et al., in CPUC R. 07-01-041 (19 November 2007), Appendix A.</p>
<p>7. Nemtzow D., D. Delury, and C. King 2007. “<a href="http://www.fortnightly.com/fortnightly/2007/03/demand-response-green-effect">The Green Effect</a>,” <i>Public Utilities Fortnightly, </i>March 2008.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Building a DR Business Case</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>A comprehensive business case for demand-response (DR) capabilities depends on a systematic process to quantify its costs, benefits and potential across a range of applications. Such a process includes the following steps:</p><p>• Define customer specific load-shapes based on particular DR technologies;<br />• Consistent with NERC, ISO/RTO, and LSE criteria, define each DR service in terms operations, certainty, response rate, and reliability;<br />• Specify the availability of the DR by customer group and location;<br />• Quantify and sum the major DR benefit streams and all related costs;<br />• Perform cost-effectiveness analysis in net-present-value terms; and<br />• Define scenarios that optimize DR resource mix and maximum value.</p><p>Major challenges include the difficulty of determining avoided capacity costs and relevant market prices for the period of the analysis. For example, T&amp;D capital cost avoided must be defined for specific locations, and congestion benefits must reflect DR location and availability. Further, optimization to determine the highest-value uses of DR requires sophisticated management and analysis. From this analysis and further experience, refinements can be made to maximize concurrent DR benefits. –<span><span class="bolditalic">ECW </span></span></p><p> </p><p> </p><p> </p><p> </p><p> </p></div></div></div> </div>
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</div></div></div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/dr-conservation">DR &amp; Conservation</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0805/images/0805-FEA2.jpg" width="1556" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
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Thu, 01 May 2008 04:00:00 +0000puradmin13815 at http://www.fortnightly.comEnergy Tech's Quantum Leaphttp://www.fortnightly.com/fortnightly/2003/11/energy-techs-quantum-leap
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Tomorrow&#039;s utility technology may be revolutionized at the molecular level.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Jennifer Alvey &amp;amp; Michael T. Burr</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - November 1 2003</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h3>Tomorrow's utility technology may be revolutionized at the molecular level.</h3>
</p>
<p>Revolutionary changes have swept through the utility industry more than once. Although the industry often receives criticism for being slow to adapt, the fact is that utilities are continually building and rebuilding their systems and strategies around changing conditions. AAAAA AASuccess in utility planning often hinges on big things-like market restructuring or an upheaval on Wall Street. It can also depend on little things-like a piece of software or a metering device. And sometimes it depends on tiny things-in the case of nanotechnology, things that didn't exist yesterday, but that just might spawn a revolution tomorrow.</p>
<p>The science of nanotechnology is no longer restricted to ivory-tower research labs. Nanostructures have already entered the marketplace, on electronics store shelves and even in the fabric of stain-resistant khakis. And now, nanotechnology is poised to bring radical new products to the utility industry-products that could revolutionize the way power is generated and delivered.</p>
<p>If the term "revolution" seems like hype, consider how the transmission system might change if power lines a centimeter in diameter could conduct a terawatt of power with virtually no resistance. Consider how the economics of distributed generation might change if fuel cell prices fell by an order of magnitude, and hydrogen could be produced cheaply on site?</p>
<p>Or what if the cost of solar cells fell by 98 percent? How might that affect power demand in the sun belt?</p>
<p>While most nanotechnology concepts are still in the lab, many are moving quickly toward commercialization. Solar-cell manufacturers, for example, are already designing factories that could begin spinning out next-generation photovoltaic (PV) materials within just a few years.</p>
<p>Given the technology's rapid progress, utilities should carefully consider its implications for their future business strategies. In that context, Fortnightly presents a brief tutorial on nanotechnology and the promise it holds for the industry.</p>
<h3>Small Science</h3>
<p>"Nanotechnology is the art and science of making stuff that does stuff on a nanometer scale," says Dr. Richard Smalley, whose discovery of the "buckyball," a new form of carbon (carbon-60), earned him the 1996 Nobel Prize in chemistry. That work led to the development of carbon nanotubes, cylindrical molecules with mechanical and electrical properties that would challenge the imagination of even the buckyball's namesake genius, the late Buckminster Fuller. These buckytubes boast a tensile strength far greater than steel and surpass the electrical conductivity of copper or silicon, but at one-sixth copper's weight.</p>
<p>Such facts attract plenty of headlines-not to mention hype. But Smalley says nanotechnology isn't really a new science; rather, it's an increasing ability on the part of chemists, physicists, and others in the hard sciences to manipulate materials at an atomic level.</p>
<p>He cites as one example modern engineered polymers like polypropylene, Kevlar, and block polymers. "These are highly engineered to do what they do. They are what they are because of putting atoms exactly where you want them to be," he says.</p>
<p>Closer to home, Smalley says high-temperature superconductors are an example of nanotechnology. "The supercurrent does what it does because of precise layering of atoms and composition. If you change it very much, it doesn't work as well."</p>
<p>Recall that just a few years ago high-temperature superconductors were the stuff of science fiction, along with cold fusion and the space elevator. While nanotechnology doesn't offer much in terms of cold fusion (or does it?), it just might revolutionize the world's energy industries in the 21st century-beginning today.</p>
<h2>A Tiny Wire Into A Big Future</h2>
<p>Carbon as a conductor? Engineers normally wouldn't consider it a candidate. Indeed, graphite, a common form of carbon, conducts electricity roughly 10100 times worse than copper. But Dr. Richard Smalley, who shared the 1996 Nobel Prize in Chemistry, believes his discovery of carbon-60 will eventually lead to carbon wires that can conduct electricity without meaningful resistance-and weigh less than half of traditional metal conductors.</p>
<p>If he can figure out how to spin a long wire composed of a particular type of the carbon nanotube he now produces, Smalley could have an impact on the electricity business that would be profound, to put it mildly.</p>
<h3>A Light Pipe for Electrons</h3>
<p>In essence, what Smalley hopes to do is spin a wire composed of a particular type of buckytube. A buckytube, which is a single carbon atom with a long, cylindrical shape, comes by its odd name from Smalley's initial discovery of carbon-60, which under a scanning tunneling microscope looks like the geodesic dome invented by Richard Buckminster Fuller. Smalley called this new carbon atom a buckyball, in honor of Fuller.</p>
<p>Both buckyballs and buckytubes are one nanometer wide-a billionth of a meter. That's just a little smaller than the diameter of a DNA double helix strand. What Smalley and others have discovered is that size really does matter; as physical materials approach a few nanometers in width, they start to behave very differently than they do in their larger, typical forms.</p>
<p>For example, carbon is normally a terrible conductor of electricity. But in nanoscale, that truism changes radically. "These little carbon tubes have an unparalleled ability to conduct electricity," Smalley says. "Plus, they have this really tricky, sexy aspect that normal mechanisms of resistance are just gone." He says electrons traveling down an armchair tube, a particular type and shape of buckytube, have only one way they can proceed, and those electrons encounter almost no mechanisms of resistance.</p>
<p>In contrast, copper and aluminum, two of the more common electrical conductors, do produce resistance. Electrons travel a few nanometers along copper or aluminum wire, meet the end of their path, and consequently "get kicked," as Smalley puts it, to the next available pathway. Of course, this deflection causes energy loss, thereby producing vibrations, i.e., heat. So the electrons traveling along a typical conducting material lose momentum to heat.</p>
<p>In an armchair buckytube, Smalley says, deflection is gone-the only thing electrons can do is move along the path of the tube. While not a superconductor, a strand of armchair tube wire would lack most types of resistance seen in metal conductors. Smalley calls this wire, which only exists in theory right now, a quantum wire. As he describes it, "This is a light pipe for electrons."</p>
<p>Smalley and other scientists have demonstrated in the lab the amount of current that can be pushed down one armchair tube: up to 20 microamps. Smalley believes that a cable of armchair tubes measuring one centimeter in diameter would have 1014 tubes in it. He calculates that centimeter-wide cable would conduct 10 terawatts of electricity. "It is just a huge, just incredible amount" of power, he says.</p>
<h3>Spinning a Powerful Future</h3>
<p>The only problem is, no one has been able to make such a cable. Yet.</p>
<p>But Smalley is hopeful. In his lab right now, he can spin a continuous fiber over a meter long-in fact, as many meters as he wants-of buckytubes. To make his fiber, he uses a method similar to that used in spinning Kevlar. But the fiber isn't composed solely, or even mostly, of the unique, highly conductive, armchair tubes. As a result, Smalley says current must hop from one tube to another, trillions of time, to traverse the fiber. The fiber's conductivity isn't very good, and that's putting it mildly.</p>
<p>Smalley predicts that if he and other scientists push hard in the next five years, an all-armchair tube nanowire will be produced. Considering that nanotubes were discovered only in 1991, his prediction may not be that far-fetched.</p>
<p>Even at his most optimistic, though, Smalley doesn't foresee the creation of nanowire hundreds of miles long. But the wire he hopes to make doesn't need to be all that long, he says.</p>
<p>To understand why, imagine that an electron is akin to a passenger on a train from Houston to Dallas, and the train and track it travels on is the equivalent of a buckytube. No one track goes all the way to Dallas, but trains on adjacent tracks will get the passenger to Dallas. Under normal circumstances, using copper as the train and track, the electron passenger would have to disembark and switch trains and tracks numerous times, possibly miss connections and have to wait, all of which would slow down the overall trip. An electron traveling along a buckytube, on the other hand, would simply disappear from one train and, in a blink, find itself traveling on another, at the same velocity. "This is what electrons and quantum particles really do in our universe," Smalley points out.</p>
<p>This phenomenon, which Smalley refers to as resonant quantum tunneling, would occur because the adjacent buckytube would be precisely identical atomically. As a result, the buckytubes seek out contact with each other, for tens of microns-which, in a nanoscale world, means 10,000 diameters of an armchair tube, and therefore plenty of opportunity for quantum tunneling by electrons.</p>
<p>Smalley's resonant quantum tunneling, like the power load limits of nanowire, is still theoretical. He freely admits that no one has verified the tunneling effect in even two adjacent tubes, let alone six or more in a fiber.</p>
<p>But if he or other scientists can pull it off, the implications are stunning for the grid.</p>
<h3>A Reason to Re-String the Grid</h3>
<p>Smalley thinks there is a high likelihood that when an armchair nanowire is made, it will have conductivity similar to copper. Even if the fiber is only half as conductive as carbon, he says, the one thing he knows for sure is what it will weigh: one-sixth the density of copper.</p>
<p>"If we can make [such a fiber] cheaply, it would be the logical replacement for every high-voltage transmission line in the world," Smalley says. He points out that most high-volatage lines now are aluminum, not because it's cheaper or more conductive than copper, but because of its lighter weight.</p>
<p>With an armchair nanowire, Smalley says, transmission lines could be much bigger in diameter and could take a larger amount of current through the same right-of-way. "That would be enough to make you re-string your cables," he notes in a bit of understatement. In addition, he thinks that his armchair nanowire would probably be good enough for use in AC settings. The cable could be insulated and grounded, and still have plenty of strength/weight ratio. And there would be no hum in such a wire, since there would be little resistance. "You wouldn't have hum, corona, RF losses, or worries about radiation fields in power lines," Smalley says.</p>
<p>Yet even if the technology can be proven in the lab, there remains the necessity to make the process work commercially. Smalley believes the cost cannot exceed $5/lb. for armchair nanowire, if it is to work commercially. He believes that goal is possible. Some types of nanofibers are being produced now commercially, at a cost of $1,000 to $100/lb. Those tubes come in a range of diameters, types, and lengths, but as Smalley points out, "it a start."</p>
<p>While Smalley is confident that an economical process for producing armchair tubes will be developed, he isn't yet chasing industry money. "Until we can get the first length made, it's premature for industry to invest," he says bluntly.</p>
<p>Yet if and when he does make a length of armchair nanowire, don't be surprised to see the world beating a path to Richard Smalley's door. </p>
<h2>Cheap PVs for All</h2>
<p>Historically, solar-electric cells, a.k.a. photovoltaics (PV), have played a diminutive role in supplying the world's electricity. The reason, of course, is cost. A watt of PV capacity costs about $90, compared with $5 for a kilowatt of diesel-engine capacity.</p>
<p>Nanotechnology, however, might be changing all of that.</p>
<p>"Our goal is to produce PV materials for less than $1 per watt," says Russell Gaudiana, Ph.D., vice president of research and development for Konarka Inc. in Lowell, Mass. "We have demonstrated every part of the process, and we have the technology in our hands to do it."</p>
<p>Nanotechnology is on the verge of revolutionizing the way PV materials are manufactured-eliminating the need for slow and costly vacuum deposition, and reducing costs by an order of magnitude or more.</p>
<p>"What nanotechnology provides is processability," says Stephen Empedocles, Ph.D., vice president of business development for Nanosys Inc. in Palo Alto, Calif. "We've changed the form factor of the inorganic material so it can be processed like a liquid."</p>
<p>The concepts and techniques vary from company to company, but essentially the idea is to produce photo-reactive materials-made of either organic or inorganic elements-that can be essentially "painted" onto a substrate. This should make it possible to produce long sheets of PV material in a roll-to-roll manufacturing process, running at high speeds in a normal atmosphere. This would not only boost the efficiency of production, but it would also dramatically reduce the cost of building PV-manufacturing factories-another barrier to today's PV technology.</p>
<p>Finally, these new PV materials are expected to be more flexible and durable than the rigid, breakable glass substrates of today's PV cells. This and other design factors might open up a whole new world for PV applications-from residential roofing systems to military uniforms.</p>
<p>These ideas might seem like the stuff of science fiction, but major companies expect to see real profit flowing from them in the not-too-distant future. For example:</p>
<ul>
<li>In late 2002, Matsushita Electric Works and Nanosys signed a contract to jointly develop building materials with integrated nano-PV cells. Matsushita-parent company of Panasonic-expects to begin selling such products in 2007.</li>
<li>Both Nanosys and Konarka have formed relationships with defense contractor SAIC to develop military and other applications for their PV technologies. Moreover, this summer the U.S. Army provided funding support for Konarka's development of flexible, field-ready PV systems-possibly even uniforms with PV nanofibers woven into the fabric.</li>
<li>In late September 2003, Electricité de France signed a cooperation agreement with Konarka to develop and launch the company's PV products "in a variety of form factors for commercial, industrial, government and consumer applications."</li>
</ul>
<p>These and other developments suggest that within a few years, mass-production facilities will begin spinning out miles and miles of inexpensive PV materials. If that happens, PV could assume a much bigger role in the power industry-possibly even becoming a viable option for distributed generation applications.</p>
<p>Getting to that point, however, requires companies to finish commercializing their technology. Demonstrating the durability of a PV system, for example, is a key step. Researchers in Europe have tested the technology on which Konarka's products are based, and they found it should deliver at least a 10-year service life in the field. Konarka is testing its own application of the technology, and so far the results are equally promising.</p>
<p>"The ultimate test is to put it up on the roof and let Mother Nature do her thing," Gaudiana says. "We haven't done that yet, but we are encouraged by the results so far." </p>
<h2>Fuel Cell Future</h2>
<p>Fuel cells are among the most promising technologies for the future of power generation. Today, however, fuel cells suffer from high capital costs, high operating costs and constraints on fuel supply and storage.</p>
<p>Nanotechnology researchers, however, are developing solutions to these nagging problems. Researchers at the Georgia Institute of Technology, for example, are focused on the fuel end of the fuel-cell challenge.</p>
<p>Scientists have long known that oxides of certain rare-earth elements (cerium, terbium and praseodymium, to be precise) can produce hydrogen from water vapor and methane in continuous inhale and exhale cycles-cycles that Georgia Tech researchers call "oxygen pumping." Theoretically, this principle could yield technology for small-scale hydrogen production, which would address the fuel transportation and storage issues that now constrain fuel cells' commercial viability.</p>
<p>The Georgia Tech studies are focused on improving the efficiency of the oxygen-pumping process. "Our progress shows surprising improvements," says Dr. Zhong L. Wang, professor and director of Georgia Tech's Center for Nanoscience and Nanotechnology. By doping iron atoms into the oxides, Georgia Tech researchers have lowered the temperatures at which the rare-earth oxides produce hydrogen, from about 1,700 C to about 400 C. Additionally, researchers have developed techniques that eliminate the need for catalysts in the process-catalysts that are expensive and that degrade with use.</p>
<p>"Our next steps are to try to reduce the temperature more and improve efficiency," Wang says. "For large-scale production, we have to improve the pumping speed by a factor of five." Although this represents a significant research challenge, if successful it could give fuel cells a major boost.</p>
<p>An even bigger boost, however, could come from developments within the fuel cell itself. Toward this end, PlugPower Inc. in Latham, N.Y., together with Albany NanoTech, an R&amp;D arm of the State University of New York, began developing nanostructures and materials for polymer electrolyte membrane fuel cells. The five-year project is aimed at achieving three main goals:</p>
<p>First, nanotechnology could improve the initial and long-term performance of fuel cells by optimizing the nano-scale structure of the electrodes. "If you put the particles down in a predetermined, structured way, you will get higher current densities, and over time the structure would probably be more stable too," says Dr. John Elter, PlugPower's vice president of research and system architecture.</p>
<p>Indeed, durability is the focus of the second goal. Today's membranes degrade with time and use, making fuel cells more costly to operate. "Nanotechnology is one path to improving stack life," Elter says. Specifically, a nano-structured electrode surface might prevent platinum particles from agglomerating and degrading the electrode's performance. "I hope we'll get an order of magnitude of improvement," Elter says. "But even if we double the stack life, that would also be very good."</p>
<p>The third goal involves reducing manufacturing costs by minimizing the amount of costly platinum required in an electrode. One approach involves using carbon nanotubes. "If you can get these tubes to stand on end on the membrane, you would have a much greater effective surface area, and the platinum loading would go down," Elter says.</p>
<p>Some nanotechnology researchers have reported staggering reductions in platinum loading-up to 98 percent reductions in some cases. Elter warns, however, that isolated lab results can be misleading, and more development will be required to achieve consistent, commercial-scale results. Still, he is optimistic about the prospects.</p>
<p>"There is a lot of promise in the literature, and tremendous momentum now," he says. "We should see a line of sight to an end game after a couple of years of research." </p>
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Sat, 01 Nov 2003 05:00:00 +0000puradmin11324 at http://www.fortnightly.comWater Heaters to teh Rescue: Demand Bidding in Electric Reserve Marketshttp://www.fortnightly.com/fortnightly/2003/09/water-heaters-teh-rescue-demand-bidding-electric-reserve-markets
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>With just a few changes in reliability rules, regulators could call on consumer loads to boost power reserves for outages and contingencies.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Eric Hirst and Brendan Kirby</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - September 1 2003</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h3>With just a few changes in reliability rules, regulators could call on consumer loads to boost power reserves for outages and contingencies.</h3>
<p> </p>
</p>
<p>In proposing a standard market design (SMD), the Federal Energy Regulatory Commission (FERC) makes clear that it wants customers to participate in wholesale power markets, such as by bidding an offer to curtail consumption, increase supply, and reduce upward pressure on prices.</p>
<p>"We believe in the direct approach of letting demand bid in the market," says FERC.</p>
<p>In fact, FERC much prefers this demand-response strategy to the more traditional special programs for load reduction, whereby regulators typically promise an incentive or subsidy to customers in return for cutbacks in usage.</p>
<p>According to the commission, letting customers bid their own demand directly in the market as a system resource "will be less costly than a program where an end-user receives payments greater than the market-clearing price to reduce its demand."<sup>1</sup></p>
<dl>
<dt>To try out FERC's idea, consider the issues and opportunities in getting retail loads to provide some of the real-power ancillary services that are required to comply with reliability rules imposed on the nation's grid system. In particular, consider the three services known as contingency reserves that are commonly deployed throughout the Northeast:</dt>
<dd>(1) 10-minute spinning reserve;</dd>
<dd>(2) 10-minute nonspinning (supplemental) reserve; and</dd>
<dd>(3) 30-minute (replacement) reserve.</dd>
</dl>
<p>These three ancillary services provide insurance against outages and other contingencies that might threaten the reliability of local or regional power grids through an interruption in service or by disrupting grid operations.</p>
<p>Under traditional practice, the electric utility industry has relied on large-scale generating plants to supply these reserves. Reliability rules are tailored to fit that assumption. Instead, consider the possibility of meeting these reserve requirements by relying on customers to trim their power consumption at crucial times.</p>
<p>Ordinarily, because the time between a major outage and full recovery is so short (15 minutes), the independent system operator (ISO) will require close communication and frequent updates on the status of the resources providing contingency reserves. During an emergency, the ISO must be able to send its request for increased output (or reduced load) to participating resources quickly, and the system operator requires the resources to confirm receipt of the dispatch order rapidly. Traditionally, the generators providing contingency reserves measure and report their output to the system operator once every several seconds. Thus, these units have sophisticated and expensive metering and telecommunications systems. In addition, the system operator requires the units to have telephone (or other voice) communication links with the control center.</p>
<p>These technical requirements were all developed with large generators in mind. However, to what extent do these requirements make sense for demand resources? That is, what does the system operator need to know about these resources, which, on average, are much smaller than the typical generator, and how frequently must this information be updated? How much can retail loads afford to spend on metering and communications, given the likely market payments for reserves of only a few dollars per megawatt per hour?</p>
<p>In fact, some demand-side resources display many of the characteristics needed to become full players in wholesale markets for contingency reserves-if regulators only would consider making some small changes in reliability rules. Consider, for example, the lowly residential electric water heater.</p>
<p>Electric water heaters can be interrupted very quickly-within seconds of notification. However, utilities can sustain the interruption conveniently for only short periods-about an hour. Should regulators bar such resources from providing contingency reserves because of requirements developed with generators-and only generators-in mind? Consider the possibility of allowing resources with shorter sustainable deployment time to provide reserves. That would accommodate loads with limited storage. And with a more sophisticated deployment of resources-dispatching one set of electric water heaters when the outage occurs, for instance, and a second set 30 minutes later, when the first set is restored to normal operation-grid operators could expand the range of reliability resources.</p>
<p>To date, however, regulators have used retail loads to support power system reliability primarily through special demand-response programs-not through bidding in markets for energy, congestion management, and ancillary services. Yet, if regulators would provide for retail loads to participate directly in wholesale power markets, those markets would expand in scope. Such participation would likely lead to lower prices (especially price spikes that are less severe), fewer opportunities for the exercise of market power, and improved reliability.</p>
<p>Yet encouraging such demand participation requires a careful review of existing reliability rules and market designs to ensure they do not unfairly exclude resources that can provide valuable services to the grid.</p>
<p>The fundamental issue here is how to get the regional reliability councils and the ISOs to think more broadly about the resources that can provide reliability services, how to value and pay for the reliability services these resources provide, and how to cost-effectively deploy such resources.</p>
<p>In this article we explore those options. We explain the nature and characteristics of ancillary services for contingency reserves, including the technical and reliability requirements imposed on resources that now provide these services. Also, we examine the design and results of markets for contingency reserves, plus the desirable characteristics of retail loads that might provide such reserves, and various ideas that might encourage participation in reserve markets.</p>
<p>Overall, we believe retail loads offer a substantial potential for aiding power system reliability through the supply of contingency reserves. Modifying the reliability requirements to accommodate demand resources and include them in revised markets should improve the efficiency of wholesale energy, ancillary-service, and congestion-management markets.</p>
<h3>Reliability Rules</h3>
<p>To ensure power system reliability, grid system operators impose various performance, metering, and communication requirements on resources that provide contingency reserves. In terms of performance, the resource must demonstrate the claimed ramping capability (in megawatts per minute, or MW/min). In addition, the resource must be able to sustain the committed output for a minimum amount of time, typically an hour or more. Also, the resource must then be able to ramp down within a specified time to its pre-contingency level so that it is positioned to respond to another outage (restoration).</p>
<p>These capability requirements ensure that, during an emergency, the resource will be able to respond as rapidly as required, and that the ISO can meet the disturbance control standard (DCS), as defined by the North American Electric Reliability Council (NERC), in its Policy 1, "Generation Control and Performance." This policy specifies two standards that control areas must meet to maintain reliability in real time.<sup>2</sup> The Control Performance Standard (CPS) covers normal operations and the DCS deals with recovery from major generator or transmission outages. Three contingency reserves are deployed throughout the Northeast: the 10-minute spinning reserve, 10-minute nonspinning (supplemental) reserve, and 30-minute (replacement) reserve. The three services are used to help control-area operators meet the DCS. For our purposes, note only that DCS requires that the system recovers from a major outage-one between 80 percent and 100 percent of the largest single contingency-within 15 minutes.<sup>3</sup> For more details, see Table 1, "Definitions of Real-Power Ancillary Services."</p>
<p>The three reserve services provide responses of different quality. Spinning reserve is the most valuable service, and therefore generally the most expensive because it requires the generator to be on line and synchronized to the grid. Because such generators are on line, they can begin responding to a contingency immediately; that is, their governors sense the drop in interconnection frequency associated with the outage and begin to increase output within seconds. Supplemental reserve, which could include generators that are already on line, is less valuable because it does not necessarily provide an immediate response to an outage. Both spinning and supplemental reserves must reach their committed output within 10 minutes of being called on by the system operator. Replacement reserve is less valuable still because it need not respond fully until 30 minutes after being deployed. Replacement reserves are used to permit the restoration of the 10-minute reserves so that these faster-acting resources are, once again, able to respond to a new emergency.</p>
<p>NERC's DCS is a performance measure; it specifies what must be accomplished (recovery within 15 minutes) without specifying how that goal must be reached.<sup>4</sup> The 10 regional reliability councils, on the other hand, set prescriptive requirements for each type of reserve. For example, the "Operating Reserve Criteria" of the Northeast Power Coordinating Council (NPCC) require that the resources providing reserves be able to sustain full output for at least 60 minutes (see Table 2).<sup>5</sup> The system operator uses this time to acquire and deploy replacement reserves. Further, NPCC requires the system operator to restore the 10-minute reserves within 105 minutes of when the DCS event occurred, to be ready to respond to another major outage.</p>
<h3>Current Practice at the ISOs</h3>
<p>Perhaps because of these extensive and expensive technical requirements, none of the three ISOs in the northeastern United States (PJM, New York, and New England) now provides for retail customer load to supply contingency reserves. Only in California do some retail loads (large water-pumping loads, to be specific) provide contingency reserves.</p>
<p>New England. Since ISO New England began operating real-time markets for energy and ancillary services in May 1999, it has experienced problems with its markets for the reserve services. Complications in the design of the ISO's day-ahead unit-commitment and its five-minute security-constrained dispatch prevented it from notifying beforehand the winning bidders in its ancillary-services markets. As a consequence, generators did not know whether they were "selected" to provide operating reserves until after the fact. In addition, the ISO might, during a major outage, call upon units that were not selected to provide reserves, and therefore they did not get paid for providing the service. In August 1999, ISO New England filed emergency market revisions with FERC. In response to the ISO's request, FERC permitted the ISO to cap the prices of operating reserves at the current hour's energy price.<sup>6</sup></p>
<p>The prices paid by ISO New England for reserves may have little meaning because of flaws in the ISO's reserve markets. During the three-year period from January 2000 through December 2002, the price of spinning reserve averaged $1.15, the price of supplemental reserve averaged $2.08, and the price of replacement reserve averaged $0.81/MWh. (During 2002, the prices averaged $1.68, $1.67, and $1.10/MWh, respectively).</p>
<p>New England implemented a new, improved market design in March 2003, based on the PJM design. This new market system, however, does not include PJM's two-part market for spinning reserve. ISO New England has not yet decided on the structure of its markets for contingency reserves and, therefore, may have no operating markets for any of the contingency reserves until late 2003.</p>
<p>New York. The New York ISO operates an integrated set of markets for energy, real-power ancillary services, and congestion management.<sup>7</sup> Because of the severity of transmission constraints in New York, especially in New York City and Long Island, New York's reserve markets have three zones.</p>
<p>Prices in the New York ISO ancillary-service markets, which do not contain the flaws that the New England markets have, might be a more reasonable indicator of what prices should be in a well-functioning market. New York, like New England, acquires roughly 600 MW of each of the three reserve services each hour. For the two-year period from January 2001 through December 2002, the prices of spinning, supplemental, and replacement reserve in New York averaged $2.74, $1.69, and $1.16/MWh, respectively. This ordering of prices is consistent with the value of each service, with spinning reserve the most valuable and replacement reserve the least valuable. (The New England prices, on average, did not follow this order.)</p>
<p>Mid-Atlantic. Until December 2002, PJM had no markets for contingency reserves. Any generator committed for service by PJM is guaranteed recovery of the costs associated with unit startup and no-load costs. To the extent these costs are not recovered from energy markets each day, PJM pays these units the difference between their operating costs and revenues for the day. These uplift costs were collected from PJM customers through an operating-reserve payment, although the nexus between these costs and reserves is ambiguous.</p>
<p>Beginning Dec. 1, 2002, PJM began operating a two-tier market for spinning reserve.<sup>8</sup> (PJM does not yet operate markets for the other contingency reserves.) Tier 1 consists of units online, following economic dispatch, and able to ramp up in response to a contingency. These units receive no upfront reservation payment but do receive an extra $50 to $100/MWh for energy produced during a DCS event. Tier 2 consists of additional capacity synchronized to the grid, including condensing units, that can provide spinning reserve. These units are paid a reservation charge, based on a real-time market-clearing price,<sup>9</sup> but they receive no extra energy payment during a reserve pickup. FERC approved the PJM market, noting, however, that it "does not contain all the attributes contemplated by the Commission in the SMD NOPR, and the PJM proposal is different from the spinning reserve markets in New York and New England."<sup>10</sup></p>
<p>The PJM markets for spinning reserve appear to be aimed at particular kinds of generating units, perhaps in recognition of the fleet of generators within its control area. As a consequence, the market design is hostile to demand resources in that there is no way for retail loads to participate in these markets.</p>
<p>Conformance With SMD. The SMD as proposed by FERC would require day-ahead markets for spinning and supplemental reserves, but not for the 30-minute replacement reserve. These markets are to be integrated with the energy market, much as New York does. This integration implies that the market-clearing price will reflect both the availability bids of the resource plus the location-specific opportunity cost of the resource. FERC also proposes operation of real-time markets for ancillary services, much as New York proposes in its real-time scheduling system. These real-time markets would differ from the day-ahead markets in that potential suppliers would not be permitted to submit availability bids. In other words, the prices for each reserve service in real time would be a function only of the real-time energy-related opportunity costs. FERC is clear that it wants these ancillary-service markets to be open to demand-side resources as well as generators.</p>
<h3>Using Demand Resources: Needs and Opportunities</h3>
<p>In the first instance, the characteristics required of contingency reserves, as determined by NERC and the regional reliability councils (see Table 2), should determine the desirable attributes of the demand resources that might provide these services. Ideally, the participating retail load should be able to be interrupted immediately, sustain the interruption for the amount of time required by the regional reliability council, return to full load within the time required by the regional reliability council for restoration (90 to 105 minutes after the contingency occurred), and then be ready to be interrupted again. The reality, however, is that DCS events occur rarely, roughly once a month.<sup>11</sup> Thus, a retail load selling reserves can count on a modest reservation (capacity) payment hour after hour, and only an occasional interruption.<sup>12</sup> Viewed in this light, the desirable demand characteristics might be driven as much by financial and convenience considerations as by physical characteristics.</p>
<p>Some industrial loads (such as a production line) might be able to shut down in response to an emergency on the electrical system. The high cost of shutting down and restarting an entire production process suggests that such a resource might be called upon only when the interruption is long. Such a large industrial load, therefore, is quite different from residential water heaters. Households with electric water heaters are unlikely to notice any performance degradation if the duration of the interruption is short. In addition, water heaters can be turned back on again very quickly, and be ready, once again, to provide contingency reserves. Other resources take much longer to be restored and rearmed to provide reserves. Thus, different retail loads are well suited to provide different services to the bulk electric system.</p>
<p>An alternative way to view demand-side provision of contingency reserves is to ask what the system operator really needs to maintain reliability. After all, the current rules were designed to accommodate large generating units, not demand resources. A more flexible set of performance-based requirements would likely encourage demand participation and improve reliability.</p>
<p>For example, there is no reason why an individual resource must maintain its emergency output or load reduction for the 60 minutes specified by NPCC. DCS performance could be just as good if some loads responded immediately and were then replaced by other load reductions after, say, 30 minutes. With this simple modification to the NPCC requirements, loads that can interrupt for 30 minutes, but not for 60 minutes, would be able to provide contingency reserves. However, the 60-minute requirement would reduce by 50 percent the amount of contingency reserves provided by loads relative to a 30-minute requirement for sustained output. Such a rule change would expand the amount of resources that could participate in ISO contingency-reserve markets, thereby improving reliability and reducing the costs of doing so. Table 3 summarizes the characteristics loads must meet to provide contingency reserves.<sup>13</sup></p>
<h3>Achieving the Vision: Nine Recommendations</h3>
<p>To help realize the potential benefits of demand-side participation, we suggest a list of nine recommended actions.</p>
<ol>
<li><b>Set Up Reserve Markets.</b> ISOs should, as soon as possible, design and open markets for all three contingency-reserve services-the 10-minute spinning reserve, 10-minute nonspinning (supplemental) reserve, and 30-minute (replacement) reserve. Without functioning markets for the reserves, it is difficult to see how retail loads could provide-and be compensated fairly for-these services.<br /> ISOs should implement markets that follow closely FERC's SMD proposal, as exemplified by the New York markets. In particular, they should adopt a day-ahead market design that integrates availability bids for the reserve services with energy bids and integrates reserves and energy in real time.</li>
<li><b>Invite Loads to Bid.</b> Loads would participate in the day-ahead reserve markets by submitting availability bids and the energy strike price (both in $/MWh) above which they would be willing to interrupt some load. Accepted load and generator bids would be treated the same way; in the event of a major outage, the ISO would dispatch generators and loads in economic merit order. Loads and generators that failed to respond to the ISO's dispatch signal during a DCS event would face the same nonperformance penalties.</li>
<li><b>Review Regional Reliability Rules.</b> The regional reliability councils should continue to review their requirements related to DCS and contingency reserves to ensure they are truly technology neutral. In addition, the councils should publish the results of the engineering and economic analyses used to justify these standards and rules.</li>
<li><b>Make Rules Technology-Neutral.</b> The NPCC requirements (see Table 2) were designed to accommodate typical generating units and are likely unsuitable for demand resources that might fully satisfy appropriate reliability requirements. For example, NPCC offers no justification for the 60-minute minimum duration of reserves. Longer duration may improve reliability, but it also raises costs and limits the number and type of resources that can provide reserves.<br /> Where, one might ask, are the data and analysis showing the economic costs and benefits of different duration times? (Or, for that matter, the other parameters shown in Table 2?)<br /> The rules should recognize the technical differences between reserves provided by large resources (whose expected performance is generally deterministic) and small resources (whose expected performance is generally statistical). The rules also should accommodate resources whose availability and size varies, especially for those resources where the variability is positively correlated with system load (in particular, weather-sensitive loads). These rules should address the reliability requirements associated with speed of response, duration of response, and speed of restoration.</li>
<li><b>Examine Metering Rules.</b> The ISOs should review the requirements they impose on resources that provide contingency reserves with respect to the frequency of metering output (or consumption) and the frequency with which these megawatt values are communicated to the ISO's control center.</li>
<li><b>Lengthen Intervals for Reporting.</b> The four-second recording and reporting requirement imposed on generators is probably not needed for retail loads that provide contingency reserves, primarily because of the much smaller size of these demand resources. It may be sufficient for large loads to record load data at the one- or five-minute level for 10-minute reserves and the five- or 10-minute level for 30-minute reserves and then report results to the ISO at the end of each month for verification and billing purposes.<br /> For small load resources, such as residential water heaters, it should be sufficient to carefully meter only a small fraction of the loads and then scale up to the population of participating loads. In both cases, there may be no reliability reason to report performance results to the ISO in near real time; it may be sufficient to provide such data at the end of each month for billing and settlement purposes.</li>
<li><b>Assess Load Characteristics.</b> ISOs, distribution utilities, and state energy offices and regulatory commissions should work together to characterize the potential demand resource for reserves in each region. This assessment would examine opportunities in the residential, commercial, and industrial sectors to see which customers and which end uses are suitable for the provision of contingency reserves. This characterization also would examine the seasonal characteristics of different loads, their storage capabilities, the speed with which the load can be interrupted and rearmed (restored), and the costs of the necessary metering and communications equipment. The resulting estimates of resource potential will be a function of reliability and market rules as well as the payments to retail loads for provision of reserve services.</li>
<li><b>Encourage Demand Participation.</b> ISOs, distribution utilities, and state energy offices and regulators should encourage loads to provide contingency reserves and to participate in the ISO markets for these reserve services. To stimulate such participation, the ISO should work with load-serving entities and other load aggregators to combine many small loads. Such aggregation should improve greatly the economics of load participation in these markets.<br /> The ISO could, based on the prior recommendation, work with the load aggregators to develop metering and communication requirements that meet the ISO's legitimate reliability needs and accommodate the needs of the load aggregators and individual retail customers. In addition, ISOs and load-serving entities (LSEs) should educate customers on bulk-power reliability issues, the importance of contingency reserves, and the role that demand resources can play in cost-effectively providing these reserves. Finally, ISOs might establish pilot programs to demonstrate the market barriers, benefits, and costs of using large and small loads to provide contingency reserves. Such programs could involve a few large industrial loads and an aggregation of residential loads (perhaps through a utility's existing direct-load-control program).</li>
<li><b>Design Protocols for Load Aggregation.</b> The ISOs should, working with LSEs and others, design load-research protocols that could be used when reserves are provided by aggregations of many small loads and which could substitute for the traditional performance measurement used for generators. Such protocols would measure the load-reductions of various types of loads under different conditions (time of day, day of the week, and season) and develop methods to forecast expected load reductions from different types of loads participating in contingency-reserve markets.</li>
</ol>
<p>These recommendations, while required to accommodate demand-side resources in participating in markets for contingency reserves, need not imply preferential treatment for any one class of resources. Rather, rules should be modified simply to incorporate a broad consideration of economic costs and benefits.</p>
<p><b></b></p>
<ol>
<li>U.S. Federal Energy Regulatory Commission, Notice of Proposed Rulemaking: Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, Docket No. RM01-12-000, Washington, D.C., July 31, 2002.</li>
<li>North American Electric Reliability Council, "Policy 1 Generation Control and Performance," NERC Operating Manual, Princeton, N.J., Nov. 21, 2002.</li>
<li>Although NERC requires recovery from a major disturbance within 15 minutes, the control-area operators require the resources providing contingency reserves to respond fully within 10 minutes. The extra five minutes often are needed by the operators to decide whether a major contingency has occurred and, if so, how best to respond.</li>
<li>Until November 2002, NERC's Policy 1 was prescriptive. NERC required that, with some exceptions, at least 50 percent of the 10-minute reserves be spinning. Perhaps more important, NERC restricted spinning reserve to "unloaded generation that is synchronized and ready to serve additional demand." Clearly, this statement excluded customer loads from providing this valuable ancillary service. NERC's new Policy 1 permits contingency reserves to be "supplied from generation, controllable load resources, or coordinated adjustments to Interchange Schedules," a very important change for demand resources.</li>
<li>Northeast Power Coordinating Council, "Operating Reserve Criteria," Document A-06, New York, N.Y., Nov. 14, 2002.</li>
<li>U.S. Federal Energy Regulatory Commission, ISO New England Inc., Order Accepting for Filing Revisions to Operable Capability Market Rules, Docket No. ER99-4002-000, Washington, D.C., Sept. 30, 1999.</li>
<li>B. Kranz, R. Pike, and E. Hirst, "Integrated Electricity Markets in New York: Day-Ahead and Real-Time Markets for Energy, Ancillary Services, and Transmission," New York Independent System Operator, Schenectady, N.Y., November 2002.</li>
<li>PJM Interconnection, "Spinning Reserve Market," Docket No. ER02-2519-000, submitted to the Federal Energy Regulatory Commission, Norristown, Pa., Aug. 29, 2002. </li>
<li>It is baffling that a competitive market would be designed to pay resources providing the identical service different amounts, and in different ways, based solely on the cost to the resource of providing the service.</li>
<li>U.S. Federal Energy Regulatory Commission, Order Accepting Spinning Reserve Market, Docket No. ER02-2519-000, Washington, D.C., Oct. 31, 2002.</li>
<li>New England has averaged 14 DCS events a year during the past five years. This is about the same rate experienced in New York and PJM.</li>
<li>We assume that retail loads will be paid for reserves just as generators are. They will receive an hourly reservation payment based on the price set in the day-ahead market and, when called upon to reduce load, they will enjoy the benefit of a lower energy payment during this time of higher energy prices. That is, loads would not receive an additional energy payment for interrupting during a DCS event.</li>
<li>E. Hirst, "Price-Responsive Demand as Reliability Resources," <a href="http://www.EHirst.com">www.EHirst.com</a>, April 2002.</li>
</ol>
<hr />
<hr />
<h3>Definitions of Real-Power Ancillary Services</h3>
<p>Ancillary services are those functions performed by the equipment and people that generate, control, and transmit electricity in support of the basic services of generating capacity, energy supply, and power delivery. These services are required to respond to the two unique characteristics of bulk-power systems: the need to maintain a balance between generation and load in near real-time and the need to redispatch generation (or load) to manage power flows through individual transmission facilities. This table lists the key real-power ancillary services, the ones that ISOs (independent system operators) generally buy in competitive markets.</p>
<table align="center" border="2" cellspadding="0" cellspacing="0">
<tbody>
<tr>
<th>Market</th>
<th>Description</th>
</tr>
<tr>
<td><b>Regulation</b></td>
<td>Generators on line, on automatic generation control, that can respond rapidly to system-operator requests for up and down movements; used to track the minute-to-minute fluctuations in system load and to correct for unintended fluctuations in generator output to comply with NERC's CPS.</td>
</tr>
<tr>
<td><b>Spinning reserve</b></td>
<td>Generators on line, synchronized to the grid, that can increase output immediately in response to a major generator or transmission outage and can reach full output within 10 minutes to comply with NERC's DCS.</td>
</tr>
<tr>
<td><b>Supplemental reserve</b></td>
<td>Same as spinning reserve, but need not respond immediately; therefore units can be off line but still must be capable of reaching full output within the required 10 minutes.</td>
</tr>
<tr>
<td><b>Replacement reserve</b></td>
<td>Same as supplemental reserve, but with a 30-minute response time, used to restore spinning and supplemental reserves to their pre-contingency status.</td>
</tr>
</tbody>
</table>
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Mon, 01 Sep 2003 04:00:00 +0000puradmin11285 at http://www.fortnightly.comNews Digesthttp://www.fortnightly.com/fortnightly/2001/02/news-digest
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Dynegy&#039;s David Francis, vice president for western power trading, testified on Dec. 21 on why he thought the ISO was bending the rules:</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Citizens&#039; Utility Ratepayer Bd. v. Kansas Corp. Comm&#039;n, Nos. 85,750 et al., Dec. 15, 2000 (Kan.App.)</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 1 2001</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 align="center"> </h1>
<h1 align="center">News Digest</h1>
<p><center> </center><br />
<p align="center"></p>
<p align="left"> </p>
<table width="100%" border="0">
<tr bgcolor="#3366CC">
<td>
<h2>Courts </h2>
</td>
</tr>
</table>
<p align="left"> <b>Rate Discount Contracts.</b> A Kansas court upheld a state commission rate case ruling that refused to impute revenues to UtiliCorp to offset revenues lost in offering rate discount contracts to large-volume electric customers, despite arguments by a consumer group that UtiliCorp was shifting costs to build its unregulated Aquila merchant energy business, since the commission earlier had OK'd the flexible tariffs that allowed such contracts, without challenge. </p>
<p align="left">Yet the court acknowledged arguments that opponents could not have fought the tariffs without actual data showing their effects, and expressed concern that state regulators had not examined possible economic effects of rate discounts when the tariffs were approved. .-B.W.R. </p>
<p align="left"><b>Ad Valorem Taxes.</b> A Louisiana appeals court instructed a state trial court to hear a suit by a gas pipeline that attacked the state's policy of levying ad valorem taxes on 25 percent of fair market value of utility property, compared to only 15 percent of the value of nonutility property. .-B.W.R. </p>
<p align="left"><b>Property Taxes.</b> A Kansas court ruled that while state tax assessors had used the "income," "cost," and "market" approaches to set the value of property for an interstate gas pipeline, it was unlawful to calculate the intrastate Kansas share by reference only to original cost, since state law required tax assessments to reflect fair market value. .-B.W.R. </p>
<p align="left"><b>Territorial Disputes.</b> Reversing a state trial judge, a South Carolina appeals court barred a rural co-op from offering electric distribution service in a residential subdivision by an adjacent town, because the population of the annexed locality exceeded 2,500, and thus could not be considered as a "rural" area eligible for service from a co-op. .-B.W.R. </p>
<p align="left"><b>Mismanagement Penalties.</b> The Vermont Supreme Court upheld a ruling by the state public service board that cut return on equity in half for Citizens Utilities-from 10.5 percent to 5.25 percent-rejecting utility claims that the penalty was confiscatory. .-B.W.R. </p>
<p align="left"><b>Nuclear Waste Fund.</b> A federal appeals court allowed a group of nuclear electric utilities to go forward with a suit asking not for money damages, but for an injunction, a declaratory judgment, and prospective equitable relief from obligations under the Energy Policy Act of 1992 to pay a share of costs incurred by the Department of Energy for decontaminating and decommissioning certain uranium processing facilities. .-P.C. </p>
<p align="left"><b>Review of Contracts. </b>A federal appeals court overturned a ruling by the FERC that had reformed a contract for sale of output from the Pilgrim nuclear plant, saying that regulators cannot remake the return on equity set by contract even if the rate appears unreasonable in light of current capital costs. The court accused the FERC of becoming "hostile" to the Mobile-Sierra doctrine, which limits the right of regulators to reform contracts they see as unfair. .-P.C. </p>
<p align="left"><b>Municipal Utilities.</b> The Ohio Supreme Court ruled that municipalities may not buy electricity solely for resale to customers outside city lines (in this case, a large industrial plant), but may sell only the surplus power left over in serving city residents. -P.C. </p>
<table width="100%" border="0">
<tr bgcolor="#3366CC">
<td>
<h2>State Legislatures</h2>
</td>
</tr>
<tr bgcolor="#99CCFF" align="left" valign="top">
<td>
<p> <b>Electric Cooperatives.</b> The Virginia, Maryland, and Delaware Association of Electric Cooperatives unveiled proposed legislation on Dec. 13 that, if passed, would allow any of Virginia's 12 electric cooperatives to vote for self-regulation, thereby removing their operations from the jurisdiction of the Virginia Corporation Commission. The Virginia legislature gave that right to the state's telephone cooperatives in a law passed in 1998.-L.A.B. </p>
</td>
</tr>
</table>
<table width="100%" border="0">
<tr bgcolor="#3366CC">
<td>
<h2>Transmission &amp; ISOs </h2>
</td>
</tr>
</table>
<p align="left"> <b>Midwest Defections.</b> Like a "spooked herd," a group of six transmission-owning electric utilities asked permission from the FERC on Dec. 19 to withdraw from the Midwest Independent System Operator, noting other utilities had said they intended to leave also, a fact that would bifurcate MISO into two noncontiguous halves and render the ISO "deficient" under FERC standards of scope and configuration. And just three days later, ComEd filed its application to quit. But Dynegy, which had asked FERC back in October for permission to leave, continued to face heavy opposition. </p>
<ul>
<li> The group of six (Central Illinois Light, Cinergy, Hoosier Energy, So. Illinois Power Co-op, So. Indiana Gas &amp; Electric, and Wabash Valley Power) said it would be "impossible" for MISO to operate without the three initial proposed defectors (Ameren also had threatened to quit), because of (1) an absence of physical interconnection among all member systems, (2) removal of crucial regional flowgates from ISO control, and (3) the impact of parallel flows between systems under the control of MISO and the proposed Alliance RTO. </li>
<li> Meanwhile, a municipal utility group led by Wisconsin Public Power Inc. continued to fight to save MISO, protesting that neither Dynegy nor ComEd had fulfilled the contractual prerequisite for withdrawal-namely, changed ownership of transmission facilities. "A single pistol shot by the commission can halt this regrettable stampede," said attorney Cynthia Bogorad, of Spiegel &amp; McDiarmid, stating the case for saving MISO. "But the shot must be heard soon." </li>
<li> According to Bogorad, the Dynegy and ComEd proposals "spooked the herd." She claimed that in the last two months of 2000, "MISO has gone from being a vital FERC-approved ISO-one having a merger agreement with MAPP, good prospects of attracting additional membership in Michigan, Canada, and the Southwest Power Pool, substantial physical infrastructure under construction (near Indianapolis), a growing staff, one $100 million bond issuance floated and [another] pending-to an organization on the edge of a cliff." .-B.W.R. </li>
</ul>
<p align="left"><b>Grid Management Charge.</b> The FERC suspended the new proposed unbundled grid management charge proposed by the California ISO to recover its administrative and operating costs, citing a likelihood that the rates might be discriminatory. .-B.W.R. </p>
<p align="left"><b>Interregional Coordination.</b> Four key players in electric policy-Enron, ELCON, EPSA, and Dynegy-plus a fifth, Reliant Energy, together asked the FERC to convene a technical conference to provide guidance on interregional coordination between regional transmission organizations (RTOs), to focus on such "seams" issues as congestion management, generation interconnection, and ancillary services, plus </p>
<ul>
<li> Protocols, emergency procedures, curtailment, market closing times. </li>
<li> Ramp rates, definition of proxy buses, etc. </li>
<li> Rate reciprocity, wheeling-in and wheeling-out. </li>
<li> Calculation of ATC (Available Transmission Capacity), TTC (Total Transmission Capability), and CBM (Capacity Benefit Margin). </li>
</ul>
<p align="left">The group noted that "few" of the recent RTO compliance filings had showed any "meaningful steps" toward interregional coordination, and also observed that in its recent investigation of bulk power markets in the Northeast, the FERC staff had found "significant seams issues that are inhibiting commerce in the region." .-B.W.R. </p>
<p align="left"><b>Arizona ISA.</b> The Arizona Independent Scheduling Coordinator asked the FERC to rehear its November order accepting the ISA's tariff, saying that, contrary to the FERC's assumption, the unique electric restructuring plan in Arizona stipulates that retail customers taking standard offer service will not see an unbundling of their retail transmission service, as will customers dealing with a competitive retailer. .-B.W.R. </p>
<p align="left"><b>Wisconsin Transco.</b> A group of Wisconsin industrial customers has protested rates proposed by American Transmission Co., the independent transco created by Wisconsin state law, complaining that ATC's proposed 12.2 percent return on common equity is "grossly" high and will hurt Wisconsin industry in competing on a national scale. As the group explained, "ATC is the first transco of its kind in the country and its formation should be handled with care." .-B.W.R. </p>
<p align="left"><b>Transco Divestiture Profits.</b> Michigan regulators OK'd a request by Consumers Energy to award 50 percent of the net premium above net book value to shareholders on the sale of its transmission assets to its proposed for-profit Michigan Electric Transmission Co. (MET), with the remaining 50 percent of such proceeds used to reduce transition costs pertaining to the state's plan for retail supply choice. </p>
<p align="left">Meanwhile, MET's first proposed open-access transmission tariff was pending before the FERC, where MET answered protests by saying it would continue to honor its existing transmission agreements. .-B.W.R.</p>
<p align="left"> <b>ICAP Deficiency Charge.</b> In a hotly contested dispute, the FERC rejected a proposed capacity deficiency charge of $0.17 per kilowatt-month to meet the installed capability (ICAP) requirement imposed in ISO New England to help maintain generating capacity reserves, and reinstated a 10-year-old, administratively determined charge of $8.75 per kW-month. The order fell under attack immediately by state regulators and industry players in the Northeast. </p>
<ul>
<li> Central Maine Power asked for an emergency stay, comparing the FERC order to the Grinch in the Dr. Seuss book, and complaining that the FERC's order would force it to shop in a bilateral contract market "where ICAP costs are running three to five times greater" than before the FERC acted. The utility said the ICAP rate "has no relevance to current New England Markets." And at National Grid USA, senior vice president Robert McLaren complained that with his company's need to go to bilateral markets to buy ICAP supplies for standard-offer customers, "each one-dollar increase in the ICAP deficiency charge would increase costs paid by [company customers] by more than $14 million per year." </li>
<li> Adding its voice, the Maine PUC complained that the new interim charge would apply retroactively and thus would offer no incentive to solicit generation-instead, the PUC said it "would only benefit those generators who were already operating by providing them a windfall." The PUC added that the ICAP order, "coming on top of already high forward prices," had forced it to dismantle the standard-offer bid process in Maine. () </li>
<li> The Massachusetts Office of Consumer Affairs also chimed in, calling the ICAP charge an "artifact" inconsistent with markets. "Today's energy market routinely clears at prices many times the real-time marginal cost of energy," said energy division legal counsel Mathew Morais. "There is no compelling need to assure all generation owners that their fixed costs will be fully recovered through an administrative charge." .-B.W.R. </li>
</ul>
<p align="left"><b>FTR Auctions. </b>The PJM Interconnection filed attachment K to its open access transmission tariff, to limit the amount of congestion credits available through a fixed transmission right (FTR) acquired through an FTR auction, to discourage FTR holders from inducing artificial congestion. As PJM explained, its market monitoring unit feared that traders could purchase FTRs in the monthly auction, but then later submit bids in the day-ahead market designed to create congestion to artificially inflate the value of FTRs. The new amendment denies any return over the FTR auction cost if such bids create more congestion in the day-ahead market than occurs in real time. . </p>
<p align="left"><b>Must-Run Contracts.</b> The FERC rejected attempts by power producer Southern Energy to force the California ISO to pay certain foregone revenues (lost opportunities to sell energy into other, more lucrative markets) in addition to the fixed option payment the generator would receive for selling the output of its generating plants under RMR contracts (for "regulatory must-run" plants) with the ISO. RMR plants are those that must be dispatched to serve customers because of transmission constraints that preclude reliance on other plants. .-L.A.B. </p>
<p align="left"><b>Congestion Management.</b> Lamenting that "no 'off-the-shelf' system is available," ISO New England announced it would take another 15 to 17 months to put in place Phase I of its proposed, single-settlement congestion management system, to include locational pricing, a security-constrained economic dispatch and financial congestion rights. Phase 2-a multi-settlement system with bidding on congestion, demand-side resources and a four-hour reserve market, would follow 12 months later. </p>
<p align="left">The ISO said the Phase 1 improvements were needed to address "major problems" with monthly uplift in transmission (congestion rent) and energy averaging $16 million and $9 million, respectively, during 2000. As it explained, "energy uplift" occurs when units are dispatched through a pay-as-bid auction at a price above the energy clearing price. It said the region's pay-as-bid auction had escalated in size and cost, leading generators to submit bids less flexible than actual unit characteristics, and depressing prices received in the parallel central clearing price auctions for energy and reserves. </p>
<p align="left">The ISO added that it had signed a contract with ALSTOM ESCA, its primary software vendor (and the vendor for PJM's multi-settlement system), and expected to sign a contract with CAP Gemini Ernst &amp; Young for certain program management services, such as integration testing. . -B.W.R. </p>
<p align="left"><b>New York Reforms.</b> The New York Department of Public Service recommended on Dec. 14 that the New York ISO should adopt a wide range of operational reforms and consumer safeguards, including a price cap of $150 per megawatt-hour on wholesale power, with "circuit breakers" set at even lower price thresholds to help detect and prevent market manipulation. </p>
<p align="left">The 125-page study, offers details on how the ISO operates (load zones, dispatch, system balancing, locational marginal pricing, congestion management, real-time markets, etc.).</p>
<p align="left"> It also calls for granting retroactive refund authority to the ISO to return ill-gotten gains to consumers. "FERC must give the NY ISO stronger enforcement power-and the ISO must use it-to reduce the potential for market power abuses," said New York PSC Chair Maureen O. Helmer. . -L.A.B. </p>
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<h2><font color="#FFFFFF">Playing Favorites<br /> Dynegy says California ISO grants sweetheart deals to out-of-state plants.</font></h2>
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<p>Claiming $2 million in loses since Nov. 1, Dynegy Power Marketing Inc. accused the California Independent System Operator of playing favorites when it goes looking for energy to cover imbalances or supply ancillary services for the next day during a "super peak," by going out of state to negotiate purchases from off-system generators at lucrative high market prices, while at the same time forcing in-state, on-system generators (like Dynegy), to honor their commitments under the Participating Generator Agreements and supply energy to the ISO on the ISO's demand through the remedial "Out-of-Market" (OOM) tariff procedure, at much lower preset prices. </p>
<p>In its complaint filed Dec. 22, Dynegy asked the Federal Energy Regulatory Commission to force the ISO, no later than March 1, to honor its "long-promised proposal" to create a third payment option (instead of the OOM rate or selling through an institutional auction like the California Power Exchange), that would permit a generator subject to OOM calls to elect to be paid its day-ahead pre-submitted bid or call price. </p>
<p>Meanwhile, the ISO insists that it is "willing to review" alternative payment approaches. But it says it will discuss the matter only if Dynegy will cooperate and respond when the ISO calls during an emergency to issue operating instructions for Dynegy's generating plants. </p>
<h3>Dynegy's David Francis, vice president for western power trading, testified on Dec. 21 on why he thought the ISO was bending the rules: </h3>
<p><b>"I AM RESPONSIBLE FOR, AMONG OTHER THINGS</b>, monitoring the supply and demand in various markets administered by the California Power Exchange, the ISO, the Automated Power Exchange and other bilateral markets. ... I make my decisions ... based on my knowledge of the operating conditions in the markets. ... </p>
<p><b>"IN SEVERAL CASES I HAVE OBSERVED THAT THE ISO HAS ACCEPTED OFFERS</b> from suppliers in the forward Super Peak markets administered by the PX and APX at prices that exceed the applicable bid cap in use by the ISO. In addition, I have witnessed instances in which Dynegy had offered energy at a compensatory price in these same markets, had the offer declined by the ISO, and then had the ISO order Dynegy to provide energy at a price dictated by the ISO's filed OOM cap, which price was in fact lower than the compensatory price that was required for the unit in question for the applicable time period. </p>
<p><b>"MY CONCLUSION FROM THESE OBSERVATIONS IS THAT THE ISO HAS BEEN WILLING</b> to negotiate with the owners of generating units that are not located within the ISO control area, and thus do not have a Participating Generator Agreement, but that the ISO has not been willing to negotiate a price above the bid cap in any instance in which a unit also has a PGA contract. ... </p>
<p><b>"MOREOVER, I HAVE WITNESSED OTHER INSTANCES</b> when the ISO has called upon an RMR [regulatory must-run] generating unit to supply energy at minimum load at the price called for under the RMR contract, and then required additional energy from the unit under the OOM procedures and at OOM-determined prices, which in most high natural gas pricing periods will be lower than an individually determined RMR price and also lower than the Imbalance Energy price for the hour(s) in question." </p>
<p align="right">David Francis <br /> Vice President <br /> West Power Trading <br /> Dynegy Power Marketing </p>
<h3>But earlier, on Nov. 22, the ISO's Randy Abernathy had dismissed such concerns in a letter to Dynegy divisional vice president Lynn Lednicky: </h3>
<p><b>DEAR MR. LEDNICKY: <br /> "RECENT ORAL AND WRITTEN COMMUNICATIONS</b> have given the ISO concerns about the willingness of Dynegy to respond to ISO instructions. This concern was the basis of a phone call this afternoon. ... </p>
<p><b>"BASED ON THAT CALL, IT IS OUR UNDERSTANDING</b> that Dynegy will respond and operate when called. Secondly there is a disagreement over compensation for those calls [demands for energy]. While the ISO is willing to review alternate payment approaches in the longer term, it is imperative in the short term that Dynegy responds to ISO operator instructions. </p>
<p><b>"SO THAT BOTH PARTIES UNDERSTAND THE NATURE OF THE ISSUE</b> before us, the potential consequences of such a failure to respond, the ISO wishes to clarify the following points. ... </p>
<p><b>"IT ALSO SEEMS NECESSARY TO CLARIFY</b> that ISO reliability instructions are not to be made a function of debates regarding payments above the current ISO price cap. The ISO is well within its authority to call upon a Participating Generator to provide energy out of market without reference to prices bid above the price cap. Consistent with FERC's orders, bids above the ISO's price caps are rejected. </p>
<p><b>"FINALLY, YOU SHOULD BE ADVISED THAT</b>, given current system conditions, any unit outages not included in annual maintenance plans submitted to the ISO are subject to investigation and possible sanctions. ..." </p>
<p align="right">Sincerely, <br /> Randy Abernathy <br /> Vice President, Client Services <br /> California ISO </p>
<p>Dynegy counters that it cannot operate its plants at the low OOM rate, claiming, for example, that with delivered natural gas costs reaching $40 per million Btu, and NO<sub>x</sub> emissions costs at $50 per pound, that its El Segundo Units 1 and 2 (called to run at a 70-MW load) require a payment of $660 per megawatt-hour just to meet marginal costs. </p>
<p>"The Participating Generators," says Dynegy, "should be paid a compensatory rate. </p>
<p>"By employing OOM provisions before exhausting competitive offers to remedy potentially thin markets," says Dynegy, "the ISO has repeatedly paid Participating Generators rates that are below short-run marginal costs." </p>
<p>Dynegy sees the ISO as playing favorites: "The ISO has repeatedly called on Dynegy to supply it energy when the only plausible motivation that can be discerned is a cost-cutting tactic designed to avoid paying a higher price demanded from other available suppliers." </p>
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<h2>Gas Pipelines</h2>
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<p align="left"> <b>Non-Spinning Reserves.</b> Finding fault with a fix-it plan proposed in September, and seeing no resolution of market flaws, the FERC told the New York ISO to maintain its existing price cap of $2.52 (plus opportunity costs) in the non-spinning reserve market, and ordered a technical conference to explore possible solutions. </p>
<p align="left">"We find that the present state of the ... market is largely the same as that which precipitated mitigation in the first place," said the FERC, noting that several market flaws continued to persist: (1) a highly concentrated market, (2) no viable plan for allowing some participants to "self-supply" their own operating reserves, and (3) no solution to the problem of moving power reserves across transmission constraints from western New York to the eastern sector. </p>
<p align="left">Dissenting commissioner Curt Hébert questioned the idea of a conference: "The exchange ... may make for an interesting salon, but will lead nowhere." . -L.A.B. </p>
<p align="left"><b>Michigan Transco Plan.</b> Facing widespread opposition, the FERC agreed to rehear its order that allowed International Transmission Co. (to be created by Detroit Edison) to charge transmission rates pegged and frozen at the level of the transmission component of Detroit Edison's retail bundled electric rates, as set by the Michigan PSC. . </p>
<p align="left"><b>Must-Run Protocols.</b> The California PUC, ISO, and Electricity Oversight Board each filed protests opposing a new formula rate tariff proposed by Southern Energy Delta and Southern Energy Protrero, which is designed to allow Southern Energy to recover any potential revenues that it might otherwise lose on reliability must-run (RMR) plants because of new ISO Tariff Amendment 26. That amendment, known as the "pre-dispatch protocol," now forces RMR plant owners to choose between two alternative forms of payment: (1) the standard RMR contract payment, which includes variable costs plus a fixed-option payment for capacity value; or (2) the market-clearing price in the day-ahead energy market, but forces RMR owners to make that choice blindly, before the day-ahead market clears and the price becomes known. </p>
<p align="left">Southern Energy claims that the RMR contract allows plant owners to file rate changes to recover unforeseen costs imposed by future ISO tariff changes, but the PUC, ISO, and EOB claim that Southern's proposed formula rate is open-ended, putting no cap on potential recoveries, which would depend on differentials between RMR contract rates and hourly markets. </p>
<p align="left">In particular, the ISO points out that the availability of the RMR contract rate actually makes RMR owners better off than other generators, since RMR plants with high startup costs or long ramp-up times can keep running and avoid off-peak losses during periods when day-ahead market rates might otherwise fall below variable running costs. The ISO opposes recovery of opportunity costs, insisting instead that RMR dispatch should allow plant owners only to recover any net incremental costs (netted against incremental revenues) incurred by making their plants available for must-run dispatch. . </p>
<p align="left"><b>Midwest ISO Defections.</b> State utility commissions in Illinois and Michigan urged the FERC to delay its review of the request by Illinois Power (through its parent company Dynegy) to withdraw from the Midwest ISO in favor of the proposed Alliance Regional Transmission Organization, alleging that Illinois Power has not shown its request to be in the public interest. </p>
<p align="left">Moreover, the Illinois and Michigan regulators say it would be wrong for the FERC to decide the matter before it issues final decisions on the MISO and Alliance RTO proposals (yet to be filed under FERC Order 2000). </p>
<p align="left">The two commissions urge the FERC to allow only one RTO for the Midwest region. They say FERC inaction "has led directly to the RTO disarray" plaguing the Midwest, creating "uncertainty and speculation" in the region. . </p>
<p align="left"><b>Public Power Participation.</b> Three separate cases before the FERC raise questions concerning the rights of municipal electric utilities to join the California ISO and file tariffs for transmission service provided over their own facilities, reflecting their own transmission revenue requirements (TRR). </p>
<ul>
<li> In one case, the city of Vernon has asked the FERC to give "fast-track" status to its application to join the ISO-the first-ever such application by a municipal utility-to overcome alleged foot-dragging by the ISO and its participating transmission owners (PTOs). The city said it was "concerned that the ISO may be giving existing PTOs a veto right" over its application, and suggested that the PTOs were "attempting to coerce concessions ... by way of refusing to execute a [revised] transmission control agreement." . </li>
<li> In the second case, also involving the city of Vernon, the FERC said that with minor modifications it would accept Vernon's proposed TRR and 11.6 percent return on equity, as submitted by the Vernon city council (the governmental body that sets Vernon's rates), but only because the council's TRR and ROE used rate-setting methods for transmission service comparable to methods already OK'd for Southern California Edison. Thus, the FERC explained that it was not deferring to the Vernon city council, but would reserve the right to review nonjurisdictional municipal activities whenever they affect jurisdictional ISO activities. . </li>
<li>ISO Determinations. In the third case, the FERC OK'd a California ISO tariff that would require municipal utilities either to file their own TRR with the FERC for review, or to allow the ISO's own revenue review panel, after approving the municipal TRR, to submit it to the FERC for further review and acceptance, despite the FERC's lack of jurisdiction over municipal utilities. . </li>
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<h2>State PUCs</h2>
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<p><b>Emergency Surcharges.</b> Facing pressure from the state's investor-owned electric utilities to provide financial relief to stave off bankruptcies, the California PUC proposed a 90-day surcharge of 1 cent per kilowatt-hour for California electric customers, applied according to usage, predicted to boost rates by about 9 percent for residential customers, by varying amounts for the small business (7 percent), medium-sized commercial (12 percent), and large commercial and industrial classes. (15 percent). . -B.W.R. </p>
<p><b>Customer Load-Shedding.</b> Idaho OK'd a tariff proposed by Avista Corp. for during periods of high wholesale power prices to buy back electricity from certain large customers (those with a single meter with a demand equal or greater than 3,000 kilovolt-amperes), which would reduce load voluntarily in exchange for a billing credit based on the prevailing wholesale market price. </p>
<p>Avista must post buyback prices on the Internet. And a "most-favored-nation" clause ensures customers that shed load will receive the highest price paid on the same day to other shedding customers, if market prices fluctuate within a 24-hour period. . </p>
<p>Meanwhile, Kaiser Aluminum decided in December to shut down its operations and temporarily lay off its 400 workers, in order to take the cheap electric power it contracted from the Bonneville Power Administration at $22.50 per megawatt-hour and resell it on the open market at prices ranging from 875 to $1,000 per megawatt-hour. Kaiser said it would pay 70 percent of salaries to idled employees. -L.A.B. </p>
<p><b>Demand Response.</b> New York instructed each of the state's electric distribution utilities to report back on plans and to establish certain minimum programs to help customers adjust demand in response to electricity market prices, including tariffs for voluntary real-time (hourly) pricing and emergency load curtailment, plus initiatives to accelerate installation of interval metering. . -B.W.R. </p>
<p><b>Electric Retail Choice.</b> Virginia asked for comments on a report by its staff that recommends (despite disagreement from Dominion Virginia Power) a "flash-cut" instead of a phased-in transition to retail electric choice, which by state law must begin by Jan. 1, 2002 and must be available to all retail customers by Jan. 1, 2005 at the very latest. . -B.W.R. </p>
<p><b>Distributed Generation. </b>Texas released a draft of its proposed Distributed Generation Interconnection Manual, governing applications to connect distributed generation resources to the power grid. The philosophy behind the manual is that distributed resources "will and should be an integral" part of the Texas electric supply system. . -L.A.B. </p>
<p><b>Nuclear Decommissioning.</b> Illinois ruled that nuclear decommissioning trust funds must be segregated by plant, so that any funds left over from decommissioning a specific plant must be refunded immediately to customers, rather than pooled with funds accumulated to decommission the owner's other nuclear plants, as proposed by Commonwealth Edison Co. </p>
<p>The commission also turned aside a request by Edison to speed up collection of decommissioning funds for nuclear plants proposed to be transferred to Exelon Genco, an unregulated affiliate. . -B.W.R. </p>
<p><b>Gas Marketer Incentives.</b> As an incentive to jumpstart competitive retail natural gas service for customers of Brooklyn Union and KeySpan Gas East, New York OK'd a rebate to competitive gas retailers of 8 percent of the gas delivery charge. The commission said the rebate would provide at least some temporary recognition that present gas transportation rates include some merchant function costs that are borne also by competitive retailers. . -B.W.R. </p>
<p><b>Standard Offer Rates.</b> Citing "inadequate bids" because of price spikes in New England power markets, Maine terminated the formal bid process to select standard-offer electricity suppliers for Central Maine Power and Bangor Hydro, and instead told the two utilities to seek out regulated transmission and distribution utilities to serve as standard-offer suppliers. </p>
<p>In a companion order, the PUC amended the standard-offer prices for medium- and large-volume non-residential customers classes served by CMP, to reflect additional costs incurred by the utility to meet its prospective obligation to supply capacity for the installed capacity (ICAP) market run by ISO New England, and its potential liability to pay the ISO's ICAP deficiency charge of $8.75 per kilowatt-month, as approved on Dec. 15 by the FERC . . -B.W.R. </p>
<p><b>Standard Offer Rates.</b> Massachusetts allowed several electric utilities to boost rates for standard offer service by 1.321 cents per kilowatt-hour to pass on to customers certain increases in fuel costs, but required two utilities to recalculate their proposed increases (1.462 cents) to reflect the most recent 12 months (instead of six months) of fuel cost data. . -L.A.B. </p>
<p><b>Billing Formats.</b> Citing the high cost to utilities of re-writing software, Ohio denied a request by state's Council of Retail Merchants to require all of the state's electric distribution utilities to adopt identical bill formats, and issued various waivers from billing format rules: </p>
<ul>
<li> Allowed to combine customer charge and delivery charge in one line item, deleting any reference to "customer charge," and to itemize "transmission service" separately from delivery charge. </li>
<li> Can redefine "delivery charge" as "charge for moving electricity over electric transmission and distribution lines." </li>
<li> After unbundling, can include separately itemized transmission and ancillary service charges in notice of "price to compare," to encourage customers to consider avoidable wires fees in addition to generation in deciding whether to switch. </li>
<li> Can eliminate "price to beat" language on assumption that customers may switch for reasons other than price. </li>
<li> Can combine customer charge with delivery charge and omit "price to compare" for demand-metered customers (as can CG&amp;E). . -B.W.R. </li>
</ul>
<p><b>Electric Metering. </b>Virginia regulators issued a recommendation to the state's General Assembly to defer any legislative action to deregulate electric metering service, given what it described as "substantial questions" regarding benefits for residential and small commercial consumers, and the lack of market development in those states that had OK'd competitive metering. </p>
<p>Virginia Power, Allegheny Power, and Delmarva Power each agreed with the commission's advice, while American Electric Power and the state attorney general had urged the commission to make retail metering competitive "as soon as practicable." . -B.W.R. </p>
<p><b>Meter Service Providers.</b> Illinois OK'd certification requirements and service standards governing meter service providers, spelling out many functions such as meter reading, installation and removal, maintenance, testing, and the collection, translation, and confidentiality of data. MSPs must maintain experienced staff on duty or on call 24 hours a day. .-P.C. </p>
<p><b>Supplier Licensing.</b> The District of Columbia required competitive electric suppliers to post a $50,000 integrity bond (vs. only $10,000 for brokers and aggregators). It rejected proposals by the People's Counsel to require bonds of $150,000 and $250,000, respectively, for suppliers with annual revenues less than or greater than $2 million. . -B.W.R. </p>
<p><b>Other December Orders. </b></p>
<ul>
<li> OK'd rules governing the "supplier of last resort" of electric service. . </li>
<li> Issued code of conduct for electric utilities and competitive power retailers. . </li>
<li> Allowed Bangor Hydro to form an unregulated subsidiary to offer fiber optic capacity to telecom carriers. . </li>
<li> Proposed rules under a new state law that allows rural electric co-op's to sell energy, water, and telecommunications services through separate business units. . </li>
<li> OK'd return on common equity of 12.1 percent in electric/gas rate case for Wisconsin Public Service Corp. . -B.W.R. </li>
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<h2>Power Plants</h2>
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<p> <b>Capacity Auctions.</b> The Texas PUC issued rules requiring all power generation companies that are affiliated with utilities to sell off entitlements to at least 15 percent of their generating capacity located in Texas, beginning 60 days prior to the implementation of customer choice, and to be completed by Jan. 1, 2007, or until 40 percent of the residential and small commercial customers served by the parent utility company have come to buy power supply from competitive retailers. </p>
<p>The required auctions will offer "slice-of-system" packages of entitlements that contain a mix of types of capacity- baseload, gas-fired cyclic, and gas-fired peaking-without tying such rights to individual plants. Affiliates of utilities owning less than 400 MW of installed capacity are exempt from the rule. .-L.A.B. </p>
<p><b>Fossil Unit Auctions.</b> New York regulators approved the $903 million sale of the Roseton (2,600-MW gas/oil units) and Danskammer (two gas/oil units, two coal/gas units, totaling 500 MW) power plants, and approved "lightened regulation" for the buyer, Dynegy, subject to a load-pocket mitigation agreement and promises to retain the 145 unionized employees at the two plants, plus at least 75 percent of the management employees. .-B.W.R. </p>
<p><b>Merchant Plant Siting.</b> The Wisconsin Supreme Court upheld an order by the state public service commission that certified construction of the gas-fired RockGen merchant power plant to supply wholesale peaking power to Alliant under a new fast-track procedure, even though the plant's size of 525 MW exceeded the 170 MW of capacity that the PSC had told Alliant to procure in the PSC's September 1997 "advance plan," and even though the statutory fast-track procedure was available only for those projects that substantially complied with the PSC's plan. </p>
<p>The court said it would not limit the size of new plant capacity constructed in eastern Wisconsin (a capacity-short area) absent any express words from the legislature setting a specific megawatt ceiling for particular resources, as the legislature had done in a different statute mandating certain utility investments in renewable energy. -B.W.R. </p>
<p><b>Interconnection Standards.</b> The FERC OK'd standards for interconnection of generating plants proposed by Consumers Energy, finding them consistent with those in other open access transmission tariffs. .-B.W.R. </p>
<p>Meanwhile, another set of new interconnections standards, proposed by Arizona Public Service Co., drew protests from Dynegy and Reliant energy, and requests for clarification on the status of small, distributed generation facilities by the state's small consumer-owned electric systems. As it has done in other similar cases, Dynegy demanded a technical conference at the FERC and complained that the APS interconnection rules would inappropriately tie interconnection service to transmission: "It is often not the generation developer or owner," said Dynegy, "that arranges for the transmission of power produced at the facility interconnected. Instead, a marketer or other customer purchasing the power would typically reserve and schedule transmission." . -B.W.R. </p>
<p><b>Nuclear Decommissioning Costs.</b> A federal appeals court ruled that the Nebraska Public Power District must refund some $78 million paid to it voluntarily by MidAmerican Energy (on NPDD's request) to cover possible future liability for decommissioning the NPPD's Cooper nuclear plant, since the plant's 1967 power sales contract had not mandated such payments, and since NPDD's right to hold MidAmerican responsible for a share of the ultimate decommissioning liability was yet contingent on a future decision by NPDD to close the plant in 2004, at the end of the contract term. .-B.W.R. </p>
<p><b>Hydroelectric Relicensing.</b> Citing canoe trips as evidence of navigation in interstate commerce, the FERC licensed a hydroelectric plant on the Blackstone River in New England where previously it had not required a license. Commissioner Hèbert dissented, arguing that the FERC should not "manufacture its own evidence" when the parties themselves cannot prove a nexus with interstate commerce. "I believe the commission's spirit of activism is unfounded," said Hébert. Docket No. UL96-1-003, 93 FERC 61,247, Dec. 13, 2000.-L.A.B. </p>
<p><b>Investment Tax Credits.</b> A federal appeals court disallowed an investment tax credit under Internal Revenue Code sec. 38 for some $7.8 million of repair work done in 1990-91 by Commonwealth Energy on its Canal No. 1 steam generating plant built in 1965. The work failed to qualify because the plant's original supply and service contract had failed to mandate any specific repair schedule or replacement of parts. .-B.W.R. </p>
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<h2>Mergers &amp; Acquisitions</h2>
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<p><b>ConEd + Northeast.</b> The New Hampshire PUC voted 2-1 to allow Consolidated Edison Inc. of New York to take over Northeast Utilities (owner of Connecticut Light &amp; Power, Yankee Gas, and Public Service Co. of New Hampshire), after receiving assurances that ConEd would not recover the $1.5 billion acquisition premium through higher rates charged by PSNH, since the state legislature earlier had barred any such rate hike as a quid pro quo for approving the utility's securitization of stranded costs. .-L.A.B. </p>
<p><b>UtiliCorp ÷Empire. </b>On Jan. 3 UtiliCorp said it would cancel plans to merge with Empire Electric Co. Several weeks earlier Arkansas regulators had rejected the deal, while the Missouri PSC OK'd the merger but rejected a key component of UtiliCorp's regulatory plana five-year rate freeze. Oklahoma said it OK'd the deal only because no party objected, but it reserved the right to scrutinize the regulatory plan in future rate cases. .-B.W.R. </p>
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<h2>Power Markets</h2>
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<p><b>California Crisis.</b> The federal appeals court in Washington, D.C. denied a request by Southern California Edison Co. to force the FERC to show cause why it had not set a new cost-based rate for wholesale power transactions in markets run by the California Power Exchange and ISO. . </p>
<p>Meanwhile, on Dec. 15, the FERC had issued its widely reported final order in the California markets case, in which it said it intended to delegate significant authority back to the state PUC to solve its own local problem. In particular, the FERC (1) renamed its price cap of $150 per megawatt-hour as a "break point," (2) set a controversial benchmark for bilateral power wholesales at $74 per megawatt-hour, and (3) excused California's electric utilities from mandatory sales into to the PX, thereby freeing up some 27,000 MW of capacity for the utilities to use to "self-supply" their own default customers. . -B.W.R. </p>
<p><b>Uniform Business Practices. </b>On Dec. 7, various energy industry groups released the second and last volume of a report on uniform business practices for retail energy markets, regarding electric metering. </p>
<p>The first volume of the report was released Nov. 22 and recommended guidelines on such issues as customer enrollment, billing, load profiling, and supplier licensing performance standards. According to EEI's Mike McGrath, group director of customer and energy service, regulators in New York, Virginia, and several other states had begun to consider the reports in their deliberations. . -L.A.B. </p>
<p><b>Benchmark Power Price.</b> Cheyenne Light, Fuel &amp; Power Co. invoked the FERC's $74 per megawatt-hour benchmark price for bilateral wholesale power contracts, announced in the Dec. 15 order on western power markets, by asking the FERC to force PacifiCorp to extend the terms of a five-year, full-requirements power sales contract, since PacifiCorp had threatened to renew the contract at prices some 650 percent higher. Cheyenne said it had relied on PacifiCorp for its power needs since 1963. . -B.W.R. </p>
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<h2>Studies &amp; Reports</h2>
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<p><b>Securitization Bonds.</b> Analysts for Salomon Smith Barney report that last year was "the slowest" of the past several in terms of volume of issuance of utility securitization bonds (PECO Energy'$1 billion issue being the only one in 2000, with deals in Texas and New Jersey postponed by legal appeals. But note that the New Jersey Supreme Court announced on Dec. 6 that it would soon release a decision allowing securitization issues to proceed in that state.) </p>
<p>Nevertheless, they believe that 2001 may well yield "a bumper crop," with the largest bond issues likely to come from Public Service Electric &amp; Gas, Connecticut Light &amp; Power, and Detroit Edison-with each company's issues exceeding $1 billion. They see as much as $10 billion in new issues in the pipeline for 2001, including the three listed utilities, plus other smaller issues from Jersey Central Power &amp; Light, Public Service Co. of New Hampshire, Reliant Energy HL&amp;P, Central Power &amp; Light, and Consumers Energy. .-B.W.R. </p>
<p><b>Electric Distribution Pricing.</b> The Regulatory Assistance Project released a study prepared for NARUC (National Association of Regulatory Utility Commissioners) suggesting that the electric distribution service may soon lose its monopoly status, and recommending that regulators consider a usage-based rate design, reflecting the volume of energy delivered, subject to a revenue cap or a performance-based scheme of regulatory oversight. . - L.A.B. </p>
<p><b>Utility Layoffs.</b> Connecticut regulators reported that as of Dec.19, electric distribution utilities in the state had terminated 193 employees over the preceding 12 months because of regulatory restructuring. Of that total, it said, none had been hired by alternative electric suppliers. .-B.W.R. </p>
<p><b>Ancillary Services.</b> Eric Hirst and Brendan Kirby, consulting for the Oak Ridge National Laboratory, report that when they studied generating plants operating in a typical small control area in the Eastern Interconnection, over two 12-day periods in February and August/September 1999, they found that native (control area) generation accounted for about 85 percent of the average hourly power required to provide load-following service, but that the contribution of native generation in supplying regulation service was "minor and ambiguous." </p>
<p>They found that compliance with control area performance standards was "good enough" that the contribution of the entire regulation component of native generation had "almost no effect." .-B.W.R. </p>
<p><b>Gas Retail Choice.</b> Connecticut regulators reported that third-party competitive gas retailers now supply about 37 percent of firm load served by the state's three major local distribution utilities. It said that the best way to foster competitive gas retailing would be to review the cost justification for elements of utility rate design, such as allocation of pipeline capacity costs, and other service attributes such as access to upstream capacity and primary delivery points. .-B.W.R. </p>
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<a href="/tags/alliant">Alliant</a><span class="pur_comma">, </span><a href="/tags/ameren">Ameren</a><span class="pur_comma">, </span><a href="/tags/american-transmission">American Transmission</a><span class="pur_comma">, </span><a href="/tags/american-transmission-co">American Transmission Co.</a><span class="pur_comma">, </span><a href="/tags/aps">APS</a><span class="pur_comma">, </span><a href="/tags/arizona-public-service">Arizona Public Service</a><span class="pur_comma">, </span><a href="/tags/arizona-public-service-co">Arizona Public Service Co.</a><span class="pur_comma">, </span><a href="/tags/atc">ATC</a><span class="pur_comma">, </span><a href="/tags/avista">Avista</a><span class="pur_comma">, </span><a href="/tags/billing">Billing</a><span class="pur_comma">, </span><a href="/tags/bonneville-power-administration">Bonneville Power Administration</a><span class="pur_comma">, </span><a href="/tags/bot">BOT</a><span class="pur_comma">, </span><a href="/tags/cap">CAP</a><span class="pur_comma">, </span><a href="/tags/central-maine-power">Central Maine Power</a><span class="pur_comma">, </span><a href="/tags/ces">CES</a><span class="pur_comma">, </span><a href="/tags/cinergy">Cinergy</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/cmp">CMP</a><span class="pur_comma">, </span><a href="/tags/comed">ComEd</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/consumers-energy">Consumers Energy</a><span class="pur_comma">, </span><a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/delmarva-power">Delmarva Power</a><span class="pur_comma">, </span><a href="/tags/department-energy">Department of Energy</a><span class="pur_comma">, </span><a href="/tags/der">DER</a><span class="pur_comma">, </span><a href="/tags/detroit-edison">Detroit Edison</a><span class="pur_comma">, </span><a href="/tags/distribution">Distribution</a><span class="pur_comma">, </span><a href="/tags/dominion">Dominion</a><span class="pur_comma">, </span><a href="/tags/dominion-virginia-power">Dominion Virginia Power</a><span class="pur_comma">, </span><a href="/tags/dynegy">Dynegy</a><span class="pur_comma">, </span><a href="/tags/eastern-interconnection">Eastern Interconnection</a><span class="pur_comma">, </span><a href="/tags/electric-transmission">Electric Transmission</a><span class="pur_comma">, </span><a href="/tags/ems">EMS</a><span class="pur_comma">, </span><a href="/tags/energy-policy-act">Energy Policy Act</a><span class="pur_comma">, </span><a href="/tags/energy-policy-act-1992">Energy Policy Act of 1992</a><span class="pur_comma">, </span><a href="/tags/epsa">EPSA</a><span class="pur_comma">, </span><a href="/tags/ernst-young">Ernst &amp; 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McDiarmid</a><span class="pur_comma">, </span><a href="/tags/spinning">Spinning</a><span class="pur_comma">, </span><a href="/tags/spinning-reserve">spinning reserve</a><span class="pur_comma">, </span><a href="/tags/transco">Transco</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/ver">VER</a><span class="pur_comma">, </span><a href="/tags/wisconsin-public-service">Wisconsin Public Service</a> </div>
</div>
Thu, 01 Feb 2001 05:00:00 +0000puradmin11562 at http://www.fortnightly.comSurviving and Thriving in the RTO Revolutionhttp://www.fortnightly.com/fortnightly/2001/02/surviving-and-thriving-rto-revolution
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>How to design tariffs to improve reliability and attract merchant generation.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Rajat K. Deb, Lie-long Hsue, Alex Ornatsky, and Jason E. Christian</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 1 2001</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><p>1 A representation of a generic interconnection, with thermal, hydro, and nuclear generation sharing a grid with a winter peaking load. </p>
<p>2 , 93 FERC 61,294, Dec. 15, 2000. </p>
<p>3 For a survey of methods, see J.W. Marangon Lima "Allocation of Transmission Fixed Charges: An Overview,", Vol. 11, No. 3, 1996. </p>
<p>4 Regulation service provides capacity under the grid operator's automatic generation control (AGC), which can respond to incremental or decremental signals in a matter of seconds. Procurement of incremental capacity (Regulation Up) may be separated from the procurement of decremental capacity (Regulation Down), as it is now in California. Payments to generators for the energy delivered by Regulation Up, or by generators for the energy not delivered by Regulation Down, are specified as part of the specific market design. </p>
<p>5 Spinning Reserve represents unloaded capacity that is connected and synchronized to the grid, and that can be dispatched for energy within 10 minutes. In addition to providing backup energy reserves (which allow units providing Regulation Up to be returned to their set points), spinning-reserve capacity provides automatic frequency control to the grid. In the typical case, steam turbines and storage hydro capacity will provide spinning reserves. Rules for dispatching, pricing, and settling the energy capacity of spinning reserves (and for the other reserve ancillary services discussed below) are important elements of the specific market design, with impacts on the broader energy markets. </p>
<p>6 Non-Spinning Reserves represents unloaded capacity that may be connected to the grid, synchronized, and delivers energy within 10 minutes of dispatch. Generation that is eligible to provide spinning reserves (since it is already connected and synchronized) is also eligible to provide non-spinning reserves. Other sources of non-spinning reserves include combustion turbines and other quick-starting facilities, loads that are prepared to curtail within the required time delay, and curtailable ("non-firm") exports to other control areas. </p>
<p>7 Replacement Reserve is technically identical to non-spinning reserves, except that it includes only the capacity that may be connected, synchronized, and loaded within 60 minutes of dispatch instruction. A wider variety of generators and loads are therefore able to provide this service. (Slow-response participants in the other reserve markets also may provide replacement reserves.) Settlement of this reserve recently has changed in the California market: Suppliers of replacement reserves that are dispatched for energy are paid the greater of the energy and the capacity price, but not both. </p>
<p>8 Our market simulation model is based on rational expected equilibrium prices (REEP) in the presence of multiple forward markets. The determination of competitive equilibrium prices in the presence of multiple markets as a non-linear game between the suppliers, who maximize their profits, and buyers, who minimize their payments. Our model, UPLAN, uses a very very large scale linear program (VVLSLP), which alternates between minimizing the buyers' payment and maximizing sellers' marginal revenue in successive iterations until a set of equilibrium prices is reached. The UPLAN Network Power Model uses an optimal power flow (OPF) algorithm to dispatch the resources cleared by the Market Simulation Model to determine the real-time imbalance prices, calculates the security-constrained load flows, manages congestion, and calculates transmission costs. UPLAN is a true multi-commodity, multi-area OPF (MMOPF) model. </p>
<p>9 The approach, and an example using the UPLAN system, is described in greater detail in Deb, "Operating Hydroelectric Plants and Pumped Storage Units," , 13, 3 (April 2000). </p>
<p>10 A fuller development of the issues and examples of this section can be found in Chapter 6 of , EPRI, Palo Alto, Calif., and LCG Consulting, Los Altos, Calif.: 2000. 1000571. </p>
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<a href="/tags/agc">AGC</a><span class="pur_comma">, </span><a href="/tags/epri">EPRI</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/hydro">Hydro</a><span class="pur_comma">, </span><a href="/tags/hydroelectric">Hydroelectric</a><span class="pur_comma">, </span><a href="/tags/network">Network</a><span class="pur_comma">, </span><a href="/tags/payment">Payment</a><span class="pur_comma">, </span><a href="/tags/regulation">Regulation</a><span class="pur_comma">, </span><a href="/tags/spinning">Spinning</a><span class="pur_comma">, </span><a href="/tags/spinning-reserve">spinning reserve</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Thu, 01 Feb 2001 05:00:00 +0000puradmin11557 at http://www.fortnightly.comNews Digesthttp://www.fortnightly.com/fortnightly/2001/01/news-digest
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Calif. PUC Application 99-08-022, proposed decisions by Barnett (Aug. 2, 2000), Neeper (Sept. 19, 2000), and Bilas (Nov. 6, 2000)</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 1 2001</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 align="center"> </h1>
<h1 align="center">News Digest</h1>
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<p align="left"> </p>
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<h2>State PUCs </h2>
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<p align="left"> <b>Retail Marketing Credits.</b> As the Federal Energy Regulatory Commission pondered remedies for volatility in California's wholesale power markets, the state PUC was considering how much the state's three major investor-owned electric distribution utilities (UDCs) must spend on power supply procurement and retail marketing for the benefit of their standard-offer default customers, and thus how much to add to the "PX Credit" that is subtracted from bundled rates to determine the wires-only charge that UDCs assess to customers that choose a competitive retailer for generation supply. </p>
<p align="left">As of late November, three proposed decisions were pending before the full commission, one issued by Administrative Law Judge Robert Barnett (with lower credits more favorable to UDCs), two more issued by Commissioners Josiah Neeper and Richard A. Bilas (with credits as much as five times higher, and thus more favorable to competitive retailers). Each decision would assess credits higher than proposed by the three UDCs-Pacific Gas &amp; Electric (PG&amp;E), Southern California Edison (SCE), and San Diego Gas &amp; Electric (SDG&amp;E)-but lower than suggested by the Office of Ratepayer Advocates (ORA) or the Alliance for Retail Markets (ARM)....</p>
<p align="left">The UDCs proposed low credits, claiming that their obligation to serve as supplier of last resort made it impossible for them to avoid a significant amount of marketing or power procurement costs. But Commissioner Neeper warned against that view: "It is not correct to assume that the utilities' default provider status will always be required, and thus that certain procurement costs are in the long run unavoidable." . </p>
<p align="left"><b>Distributed Generation.</b> In updating its current rules, New York barred electric utilities from requiring any sort of insurance coverage as a condition for interconnection by electric customers of distributed generation facilities of 300 kilovolt-amperes or less. </p>
<p align="left">Instead, the commission will leave it up to private markets to craft insurance arrangements for small-scale generators that install DG plants. </p>
<p align="left">The commission also will allow customers to lease their on-site DG units to third parties, and will not limit the standard interconnection contract to a specific term (e.g., five years), despite hard lessons learned from cogeneration contracts that locked in rates at out-of-market levels. </p>
<p align="left">"Standardized [DG] contracts do not include payments for energy," said the commission. "It is not unreasonable for us to require utilities to enter into interconnection agreements that last for the lifetime of the DG unit." . </p>
<p align="left"><b>On-Site Solar.</b> By contrast to New York (see above), Florida will require proof of liability insurance no less than $100,000 before allowing electric customers to interconnect photovoltaic generating systems smaller than 10 kilowatts under a pilot program with Tampa Electric. </p>
<p align="left">The utility will pay customers 9 cents per kilowatt-hour for their solar generation, or 1 cent less than the premium price for the solar-generated power under a "green" energy program OK'd for Tampa Electric back in September. . </p>
<p align="left"><b>Electronic Data Interchange.</b> New York invited comments on proposals offered on Oct. 10 by the state's EDI Collaborative for using Electronic Data Interchange in business processes for enrolling and removing retail direct access customers. . </p>
<p align="left"><b>Performance-Based Rates.</b> Rejecting arguments from power producers, industrial customers, and the state's public advocate, Maine found no need to incorporate a mechanism to share excess earnings with ratepayers in approving a seven-year, performance-based, price index formula to set rates for electric transmission and distribution for Central Maine Power. </p>
<p align="left">Instead, the PUC set a high productivity figure as an offset to the inflation adjustment allowed under the formula. The offset will equal the inflation rate in 2001, and rise from 2 percent to 2.9 percent by 2007-nearly double the offsets proposed initially by CMP.. </p>
<p align="left"><b>Standard Offer Entry/Exit Fees.</b> Maine opened an investigation of entry or exit fees for standard offer power supply service, citing "gaming" threats posed by customers who switch back and forth between competitive and SO services. The PUC posed several questions for comment, such as: </p>
<ul>
<li> Cause of Gaming. Should the rule address only those problems that stem from market price fluctuations, or should it consider problems that stem from ratemaking formulas used in calculating SO rates? </li>
<li> Type of Fee. Require an "opt-out" fee (payable if a customers leaves SO service too soon), or instead charge an "entrance" fee on return to SO service? </li>
<li> Revenue Allocation. How to apportion revenues from opt-out fees if the identity of the SO provider changes between the time a customer signs up and later leaves? </li>
<li> Aggregation Deals. How to handle the case when customers enroll in SO service as an aggregated group, but then leave SO service individually? . </li>
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<h2>Studies &amp; Reports</h2>
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<p> <b>Transition to Deregulation. </b>The "prolonged and muddled transition" from regulation to market control of the North American electric power industry, including recent highly publicized brownouts and volatile prices, has raised public concerns about the industry's ability to deliver reliable service at affordable costs, according to a report by Cambridge Energy Research Associates and Arthur Andersen. </p>
<p>The report, "Electric Power Trends 2001," says that potential consequences of the transition difficulties include the likelihood of renewed political intervention and re-regulation that could worsen transmission gridlock and increase the industry's valuation gap. Contact Lauren Laidlaw at 617-441-2604 or <a href="mailto:llaidlaw@cera.com">llaidlaw@cera.com</a>. </p>
<p><b>Wisconsin Power Markets.</b> Power producers may well be able to exercise market power in Wisconsin (especially in northern Wisconsin and Upper Michigan), thereby frustrating development of retail electricity competition in the state, even after new transmission capacity is added, according to a study commissioned by the Wisconsin PSC and conducted by the consulting firm of Tabors, Caramanis and Associates of Cambridge, Mass. </p>
<p>Yet the report adds that a workably competitive market would not produce stranded costs or adverse effects on employees at generating facilities, but would lead to "significantly lower rates." </p>
<p>The authors suggest two remedies: (1) Require Wisconsin Electric Power Co. to divest its generation assets among three separate independent owners, and (2) force plant owners to dedicate a significant portion of their capacity to fixed price contracts for retail customers taking standard offer service. . -L.A.B., P.C. </p>
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<p align="left"><b>Gas Franchise Forfeiture.</b> North Carolina opened an inquiry on whether Frontier Energy LLC has made enough progress to initiate gas distribution service in newly certificated and previously unserved areas to avoid forfeiture of its franchise for lack of service. . </p>
<p align="left"><b>Gas System Outages.</b> Citing potential harm to customers, Wyoming declined to fine K N Energy for a "series of preventable human errors" that regulators said had represented "grossly negligent and unjustifiable conduct" and had led to a total failure of the utility's retail gas distribution network for some 10,000 retail customers (business and residential) in the city of Laramie, back on July 18. Instead, the commission told K N to make improvements and supply numerous followup reports, and denied rate recovery of expenses incurred by the company (about $317,000) to shut down and relight the system during the emergency. . </p>
<p align="left"><b>QF Cost Recovery.</b> Montana denied a request by Montana Power Co. to boost the generation component of rates to recover higher purchased power prices paid to qualifying cogeneration facilities, saying the utility failed to make the requisite showing of "irreparable financial harm," as required to earn an exception from the rate moratorium imposed under the state's electric restructuring legislation that froze rates to levels in place on July 1, 1998. . L.A.B. </p>
<p align="left"><b>Public Benefits Programs.</b> New Hampshire issued instructions for designing, evaluating, and funding public purpose programs for electric utilities and customers: </p>
<ul>
<li> Low-Income Assistance. Rejected a flat rate discount in favor of fluctuating payments designed to cut electric bills to 6 percent and 4 percent of income, respectively, for heating and non-heating customers. . </li>
<li> Energy Efficiency. OK'd a cost-benefit test with a 15 percent adder for nonquantifiable environmental benefits, and told electric utilities to develop PAYS programs ("Pay As You Save"), with program funding costs repaid out of bill savings, so as to eliminate up-front costs or split incentives. . </li>
<li> System Benefits Charge. Allocated revenues from the 2-mill system benefit charge on a 60-40 basis between two types of public benefit programs-i.e., $0.0012 per kilowatt-hour for low-income assistance, and $0.0008 per kilowatt-hour for energy/conservation programs. . </li>
</ul>
<p align="left"><b>Single-Retailer Tariff.</b> New York OK'd a single-retailer natural gas tariff for Rochester Gas &amp; Elec. Corp., whereby RG&amp;E will act as a wholesaler only, providing distribution service at wholesale to unregulated retail marketers, who in turn will repackage the distribution service with the gas commodity to retail gas customers, who will look to the unregulated marketer for all billing and merchant functions. . </p>
<p align="left"><b>Securitization Bonds.</b> Regulators in Michigan and Connecticut authorized Detroit Edison, Consumers Energy, and Connecticut Light &amp; Power to issue bonds to securitize stranded and regulatory assets. </p>
<ul>
<li> OK's bonds to finance $1.8 billion of regulatory assets, with a surcharge of $0.004239 per kilowatt-hour to recover the assets. . </li>
<li> OK's bonds to finance $468.5 million in regulatory assets, with finance surcharge of $0.0025 per kilowatt-hour to recover the assets. . </li>
<li> OK's rate reduction bonds to securitize some $1.5 billion in regulatory and stranded assets. . L.A.B. </li>
</ul>
<p align="left"><b>Stranded Costs.</b> In an open meeting held Nov. 1, the Texas PUC suggested that electric utility ratepayers should be allowed to benefit in some way if electric utilities in the state might end up with "negative" stranded costs (assets worth more than book value), even though state law does not allow for calculation of such negative balances, and asked its staff to produce a final order to deal with the possibility. </p>
<p align="left">With recent price runups in natural gas and wholesale power markets, the PUC predicted a higher-than-expected value for nuclear generation owned by utilities. It questioned whether it would have to "undo" various mitigation measures it had adopted earlier (e.g., allowing accelerated depreciation on power plants liable to stranding). P.C. </p>
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<h2>Electric Reliability</h2>
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<p> <b>Mandatory Federal Standards.</b> Acknowledging failure in trying to get Congress to pass federal legislation, the Department of Energy asked for comments on whether it should open its own rulemaking case to compel the Federal Energy Regulatory Commission to impose mandatory standards for electric reliability. The DOE asked for comments on several questions, including: </p>
<ul>
<li> Current Rules. What's wrong with the current system, and have violations of standards jeopardized reliability? </li>
<li> FERC Authority. What can the FERC do under current authority? Can it impose standards or delegate that task to a separate, self-regulating, reliability organization (SRRO)? </li>
<li> RTO Issues. How would regional transmission organizations interact with an SRRO? . </li>
</ul>
<p><b>NERC 10-Year Assessment.</b> The North American Electric Reliability Council (NERC) released its reliability assessment for the years 2000-2009, predicting a sharp turnaround in availability of generation supply, with higher summer reserve margins by 2004 in most of the country-in the Eastern and Western Interconnections, but not in ERCOT, where NERC projects that margins will rise slightly through 2002, but then begin to fall. Consistent with that prediction, NERC projects greater growth in demand and load in the ERCOT than in the West or East. The study also reveals a sharply higher incidence nationwide of requests for transmission line loading relief (TLR), beginning in April 2000, and continuing through the remainder of the year at a much higher plateau than in prior years. </p>
<ul>
<li> Study projects 1.9 percent annual growth nationwide in both electric demand and load, but stronger rates in the West (2.1 percent increase) and ERCOT (2.7 percent) than in the East (1.7 percent). </li>
<li> Increasing through 2004, especially in the Northeast (NPCC) and the Mid-Atlantic (MAAC), and to a lesser degree in Florida (FRCC) and the West (WSCC), but flat or falling slightly during the same time frame in the Midwest (ECAR and MAPP), and the South- east (SERC). Margins are projected at dangerously low levels in Texas (ERCOT) by 2009, based on announced construction plans for new merchant generation. </li>
<li> TLR logs show a steady growth in requests for line relief since 1997, plus an approximate tripling of TLR events from 1999 to 2000 during almost all months. </li>
<li> NERC projects that production of natural gas in the Western Canadian Sedimentary Basin (and Canadian exports to the United States) will remain roughly constant through about 2012, when each will begin to fall, with WCSB production unable to fill export pipeline capacity by 2018. See <a href="http://www.nerc.com/~filez/rasreports.html">www.nerc.com/~filez/rasreports.html</a>. </li>
</ul>
<p><b>Michigan Grid Constraints. </b>The Michigan PSC directed the state's three largest electric utilities (Consumers Energy, Detroit Edison, and Indiana Michigan Power) to assess and report on near-term generation and transmission capacities, plus any planned upgrades or additions, and how such capacity may affect service reliability and retail open access programs this coming summer. </p>
<p>The PSC expressed concern that long-term contracts may have tied up grid capacity and imposed "artificial" shortages. . L.A.B.</p>
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<h2>Transmission &amp; ISOs </h2>
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<p align="left"> <b>Non-Spinning Reserves.</b> Finding fault with a fix-it plan proposed in September, and seeing no resolution of market flaws, the FERC told the New York ISO to maintain its existing price cap of $2.52 (plus opportunity costs) in the non-spinning reserve market, and ordered a technical conference to explore possible solutions. </p>
<p align="left">"We find that the present state of the ... market is largely the same as that which precipitated mitigation in the first place," said the FERC, noting that several market flaws continued to persist: (1) a highly concentrated market, (2) no viable plan for allowing some participants to "self-supply" their own operating reserves, and (3) no solution to the problem of moving power reserves across transmission constraints from western New York to the eastern sector. </p>
<p align="left">Dissenting commissioner Curt Hébert questioned the idea of a conference: "The exchange ... may make for an interesting salon, but will lead nowhere." . -L.A.B. </p>
<p align="left"><b>Michigan Transco Plan.</b> Facing widespread opposition, the FERC agreed to rehear its order that allowed International Transmission Co. (to be created by Detroit Edison) to charge transmission rates pegged and frozen at the level of the transmission component of Detroit Edison's retail bundled electric rates, as set by the Michigan PSC. . </p>
<p align="left"><b>Must-Run Protocols.</b> The California PUC, ISO, and Electricity Oversight Board each filed protests opposing a new formula rate tariff proposed by Southern Energy Delta and Southern Energy Protrero, which is designed to allow Southern Energy to recover any potential revenues that it might otherwise lose on reliability must-run (RMR) plants because of new ISO Tariff Amendment 26. That amendment, known as the "pre-dispatch protocol," now forces RMR plant owners to choose between two alternative forms of payment: (1) the standard RMR contract payment, which includes variable costs plus a fixed-option payment for capacity value; or (2) the market-clearing price in the day-ahead energy market, but forces RMR owners to make that choice blindly, before the day-ahead market clears and the price becomes known. </p>
<p align="left">Southern Energy claims that the RMR contract allows plant owners to file rate changes to recover unforeseen costs imposed by future ISO tariff changes, but the PUC, ISO, and EOB claim that Southern's proposed formula rate is open-ended, putting no cap on potential recoveries, which would depend on differentials between RMR contract rates and hourly markets. </p>
<p align="left">In particular, the ISO points out that the availability of the RMR contract rate actually makes RMR owners better off than other generators, since RMR plants with high startup costs or long ramp-up times can keep running and avoid off-peak losses during periods when day-ahead market rates might otherwise fall below variable running costs. The ISO opposes recovery of opportunity costs, insisting instead that RMR dispatch should allow plant owners only to recover any net incremental costs (netted against incremental revenues) incurred by making their plants available for must-run dispatch. . </p>
<p align="left"><b>Midwest ISO Defections.</b> State utility commissions in Illinois and Michigan urged the FERC to delay its review of the request by Illinois Power (through its parent company Dynegy) to withdraw from the Midwest ISO in favor of the proposed Alliance Regional Transmission Organization, alleging that Illinois Power has not shown its request to be in the public interest. </p>
<p align="left">Moreover, the Illinois and Michigan regulators say it would be wrong for the FERC to decide the matter before it issues final decisions on the MISO and Alliance RTO proposals (yet to be filed under FERC Order 2000). </p>
<p align="left">The two commissions urge the FERC to allow only one RTO for the Midwest region. They say FERC inaction "has led directly to the RTO disarray" plaguing the Midwest, creating "uncertainty and speculation" in the region. . </p>
<p align="left"><b>Public Power Participation.</b> Three separate cases before the FERC raise questions concerning the rights of municipal electric utilities to join the California ISO and file tariffs for transmission service provided over their own facilities, reflecting their own transmission revenue requirements (TRR). </p>
<ul>
<li> In one case, the city of Vernon has asked the FERC to give "fast-track" status to its application to join the ISO-the first-ever such application by a municipal utility-to overcome alleged foot-dragging by the ISO and its participating transmission owners (PTOs). The city said it was "concerned that the ISO may be giving existing PTOs a veto right" over its application, and suggested that the PTOs were "attempting to coerce concessions ... by way of refusing to execute a [revised] transmission control agreement." . </li>
<li> In the second case, also involving the city of Vernon, the FERC said that with minor modifications it would accept Vernon's proposed TRR and 11.6 percent return on equity, as submitted by the Vernon city council (the governmental body that sets Vernon's rates), but only because the council's TRR and ROE used rate-setting methods for transmission service comparable to methods already OK'd for Southern California Edison. Thus, the FERC explained that it was not deferring to the Vernon city council, but would reserve the right to review nonjurisdictional municipal activities whenever they affect jurisdictional ISO activities. . </li>
<li>ISO Determinations. In the third case, the FERC OK'd a California ISO tariff that would require municipal utilities either to file their own TRR with the FERC for review, or to allow the ISO's own revenue review panel, after approving the municipal TRR, to submit it to the FERC for further review and acceptance, despite the FERC's lack of jurisdiction over municipal utilities. . </li>
</ul>
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<h2>Business Wire </h2>
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<p>Avista Corp. subsidiary <b>Avista Advantage</b> has reached an agreement with <b>EnerTech Capital Partners</b> for a strategic business investment that includes capital, access to a wide network of resources, hands-on support, and counsel. The investment will be used to help refine, expand, and market Avista Advantage's growing suite of facility cost management service offerings and includes the first round of private equity financing. Terms of the agreement were not released. </p>
<p>Boston-based consulting firm <b>EFI Inc.</b> has teamed with <b>Savoy WebEngines Inc.</b> and been awarded $524,952 from the <b>U.S. Department of Energy</b> to bring to market the Internet-based energy management system, the Savoy WebEngine. The grant was one of 18 research and development projects selected by DOE to receive funding. The projects are designed to improve energy efficiency of commercial and multi-family residential buildings across the country by using less electricity and reducing pollution from heating and cooling systems. </p>
<p><b>Sermatech International</b> has acquired <b>Turbine Technology Services Corp.</b>, a high-technology engineered products and services provider for gas turbine and combined cycle power plants. Terms of the deal were not disclosed. "As the installed base of gas turbines has grown rapidly, power generation plant owners have been looking for ways to effectively reduce costs and to manage the complex outages required to keep their machines running efficiently," said James McCabe, president of Sermatech. The capabilities of Turbine Technology Services complement our growing core of gas turbine products and services enabling us to meet our customers' need for comprehensive maintenance packages." </p>
<p>In preparation for customer choice and retail competition beginning in Alberta on Jan. 1, 2001, <b>EPCOR</b>, an Alberta-based utility services provider, has implemented an advanced billing system from <b>Itron Inc.</b> to meet the billing needs of its commercial and industrial energy customers. Itron's MV-PBS is a client/server-based billing and market settlement solution that produces customized bills and invoices to meet the needs of commercial, industrial, and wholesale energy customers that purchase energy under a variety of complex rates, supply contracts, and schedules. </p>
<p><b>Convergent Group Corp.</b> has signed a definitive agreement with a wholly-owned subsidiary of <b>Schlumberger Ltd.</b>, whereby the Schlumberger subsidiary will acquire 71.7 percent of the outstanding Convergent Group common shares for $8.00 per share in cash. Convergent Group management and employees will own approximately 26 percent of the remaining shares, and <b>Cinergy Ventures LLC</b>, a unit of Cinergy Corp., the firm's largest client, will retain equity in the firm, holding the remaining ownership interest. -C.J.L.</p>
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<h2><font color="#FFFFFF">Power Markets <br /> California Prices: Real or Rigged? </font></h2>
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<p align="center"> <b>FERC review only opens up an endless debate.</b> </p>
<p><b>By Thanksgiving, after the Nov. 22 deadline had passed</b> at the Federal Energy Regulatory Commission for submitting comments on the remedies the agency had proposed to tame runaway power prices in California and the West, the whole question had split into three separate and distinct debates: </p>
<ul>
<li> Why should the "filed rate doctrine" bar retroactive refunds when prices are set by markets, not by tariffs? </li>
<li> Do California's high prices stem from anticompetitive behavior, market design, or simple scarcity of supply? </li>
<li> If a price cap is warranted, then what is the just and reasonable price? </li>
</ul>
<p>On Nov. 22, San Diego Gas &amp; Electric and Southern California Edison both asked the FERC to change its tune and order retroactive refunds of excess power costs. Edison saw the key problem as one of market power and abuse. By contrast, SDG&amp;E did not insist that market manipulation was to blame, but instead urged the FERC to cap wholesale prices based on costs incurred by generators. </p>
<p>Meanwhile, PG&amp;E asked the California Public Utilities Commission to stabilize rates and proposed a five-year stabilization plan that would lock the cap on wholesale power costs at 6.5 cents per kilowatt-hour ($65/MWh) for residential and small business customers, under a recently enacted state law that otherwise would give discretion to the PUC to adjust the 6.5-cent ceiling. But even that modest proposal could lead to trouble. In mid-November, California PUC commissioner Carl Wood suggested in a draft decision that the statutory 6.5-cent plan could make San Diego Gas &amp; Electric Co. even worse off, if significant numbers of large-volume industrial, commercial, and agricultural customers take advantage of the 6.5-cent plan, and if purchased power costs continue to rise. The PUC was expected to review Wood's proposed decision on Dec. 7. . </p>
<p><b>Retroactive Refunds?</b> At a public hearing before Chairman James J. Hoecker and Commissioner William Massey of the FERC, held in San Diego Nov. 14, California Gov. Gray Davis had again called on the FERC to require retroactive rate refunds for San Diego consumers. </p>
<p>"Your plan will make things worse next summer," Davis said, referring to the proposed order. </p>
<p>The governor's words echoed the comments of California state Sen. Steve Peace, who had testified a week earlier at the FERC in Washington, D.C. on Nov. 9, calling for retroactive refunds. Peace had questioned why the FERC should apply the filed rate doctrine (barring retroactive refunds) when rates are based not on cost of service, but on competitive forces. </p>
<p>"There's no filed rate," argued Peace, "because there is no cost of service." </p>
<p>In fact, just a few days earlier, Congressman Bob Filner (D-Calif.) had introduced new federal legislation (H.R. 5626) to amend the Federal Power Act to allow the FERC to order refunds of rates to the extent they exceed the just and reasonable level, with interest accrued "from the date on which the rate or charge was paid," in the special case where the FERC has prescribed market-based rates for the transmission or sale of electricity. </p>
<p>Refunds could prove problematic, however. Chairman Hoecker pointed out the problem in a statement he released on Nov. 17, asking for guidance. </p>
<p>"If the commission were to order refund of excessive rates," asked Hoecker, "how would we determine the excess in a market-based rate environment? What would be the just and reasonable rate? Who would be responsible for refunding the overcharge?" </p>
<p><b>Market Power or Broken Markets?</b> Testifying before the FERC on Nov. 9, Diane Jacob, chairwoman of the San Diego County Board of Supervisors, had laid it all on the table. </p>
<p>"I liken what is happening in San Diego to white collar crime and no less," she said. </p>
<p>Others blame the market structure. In comments filed Nov. 21 on behalf of ELCON, the Electricity Consumers Resource Council, and various industrial customer groups, attorney Sara Schotland reminded the FERC that her clients had been warning of structural flaws in the California market for years, especially the idea of dividing the power exchange from the independent system operator, and thus forcing the ISO to work through third-party scheduling coordinators to balance the grid in real time. </p>
<p>"As far back as July 25, 1994," said Schotland, "we warned that the U.K. model is better left in the U.K., and identified fundamental problems with the power exchange concept that unfortunately have been realized." </p>
<p>In their paper attached to comments filed by Southern California Edison, consultant Scott Harvey and professor William Hogan offered new explanations of structural market flaws in California. </p>
<p>"Prices have been high in California," they wrote, "surprisingly high." </p>
<p>In particular, Harvey and Hogan noted that because of the sequential nature of California markets, with a day-ahead auction for energy as a consumer product, followed by real-time auctions for ancillary services and energy system balancing, they believed that even those sellers lacking market power were withholding output from one auction to get a higher price in a later auction, thus causing day-ahead energy prices to rise to the level of opportunity costs represented by higher prices in later-clearing markets. </p>
<p>Surprisingly, however, they advised against abandoning the single-price principle in favor of a pay-as-bid auction. According to Harvey and Hogan, "pay-as-bid pricing systems introduce inefficiencies that raise market prices in a manner that can be hard to distinguish from the exercise of market power." </p>
<p><b>Costs, Caps, and Scarcity.</b> At the other end, many power marketers and power plant owners, such as Dynegy, Enron, and Calpine, have begun to argue that prices are not really out of line-they simply represent rising costs and scarcity of supply when compared with demand. </p>
<p>The marketers and power producers not only oppose the idea of price caps, but question how the FERC can hope to calculate a "just and reasonable" price for power, based on fuel prices, plant operating costs and characteristics, and the owner's profit expectations, when costs are changing so rapidly and each power plant and owner is unique. </p>
<p>Comments offered at the FERC's Nov. 9 hearing in Washington suggested that a reasonable power price, based on the costs of a gas-fired peaking plant, might vary anywhere between $75 and $350 per megawatt-hour, or even higher, even with the heat rate held constant, depending on such factors as the number of hours in the year during which the plant operates, and the number of years that the owners expect to wait before recovering their fixed costs. </p>
<p>Anyone eager to define the cost of generation should read the California PUC's motion in which it literally begs the FERC to help it force power plant owners to answer subpoenas requiring them to supply cost data. "The CPUC wants to know how much money each generating and trading entity is making." </p>
<p>On Nov. 14, California PX CEO George Sladoje announced the formation of a "Blue Ribbon Panel," led by Professor Alfred Kahn, to investigate criticisms of California's power markets and to determine whether the current rules for setting market-clearing prices in the PX day-ahead market produce a "fair and efficient" electricity price. The panel was to solicit comments from interested parties and meet in New York City on Nov. 28, and later in San Francisco on Dec. 12. </p>
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<h2>Mergers &amp; Acquisitions </h2>
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<p><b>Sierra + PGE.</b> Still following its old policy predating Order 642, FERC allowed Sierra Pacific Resources to acquire Portland General Electric, relying on two promises by the merged company to cap prices and to limit any firm reservations to one hour on any transmission facility that uses the constrained Alturas intertie. . </p>
<p><b>Federal Review. </b>Two-and-one-half years after issuing its original rulemaking notice, the FERC finally approved a final rule governing approval of electric and gas utility mergers, largely ratifying its existing "Appendix A screen" already used to evaluate horizontal competition, but with some new wrinkles added, such as adding ancillary services and real-time reserve markets to the list of relevant products. </p>
<p>The FERC also called for a technical conference to evaluate the use of computer models to simulate markets. </p>
<p>Nevertheless, the FERC largely ignored concerns raised by the Federal Trade Commission and others about relying on the merging utilities to supply and evaluate their own data, without independent validation. They noted that the Hart-Scott-Rodino law allows regulators to collect evidence from third parties, and allows for confidential, off-the-record give-and-take exchanges that may serve better to uncover threats to competition. </p>
<p>Commissioner Curt Hébert voted for the order but suggested that the FERC lacks antitrust experience and instead should rely more on the FTC and the Department of Justice for merger review. . L.A.B. </p>
<p><b>PUC Merger Review.</b> North Carolina regulators issued rules forcing electric or gas utilities seeking merger approval to submit a cost-benefit study and a market power analysis, despite opposition from Duke Energy and Carolina Power &amp; Light, which preferred to leave antitrust issues to federal agencies. . </p>
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<h2>Power Plants </h2>
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<p> <b>Expedited Licensing.</b> Faced with tight reserve margins and resulting political pressure, the California Energy Commission by a 4-0 vote on Nov. 15 adopted emergency regulations to implement the state's new six-month "fast-track" process for licensing thermal power plants, required by Assembly Bill 970, signed into law on Sept. 6. . -C.J.L. </p>
<p><b>AFUDC Financing.</b> Citing figures that it found "excessive," the Florida PSC denied a request by the investor-owned Florida Public Utilities Co. (FPUC) to accrue allowance for funds used during construction (AFUDC) at a rate of 11.17 percent to finance construction of a gas pipeline gate station and lateral to serve a new 200-megawatt, gas-fired power plant to be constructed by a third party. </p>
<p>Nevertheless, the PSC did OK a project-specific 14.4 percent return on equity (ROE), yielding an 11.17 percent return on net project investment, even though FPUC's current overall ROE (as set by state regulators) was only 11.4 percent. </p>
<p>The PSC explained that the higher ROE was the product of negotiations between a "willing buyer" and a "willing seller." . </p>
<p><b>Downwind Pollution. </b>The U.S. Justice Department, Environmental Protection Agency, and the State of New York have reached an agreement in principle with Virginia Power requiring the company to cut emissions (SO<sub>2</sub> and NO<sub>x</sub>) from its eight coal-fired power plants, pay a $5.3 million civil fine, surrender certain SO<sub>2</sub> emissions allowances, and contribute $13.9 million in environmental projects. </p>
<p>The agreement comes a year after the EPA and New York-and later New Jersey, Vermont, and Massachusetts-announced intentions to sue the owners of several Midwestern and Mid-Atlantic coal-fired power plants, two of which were owned by Virginia Power, for violating the federal Clean Air Act. -C.J.L. </p>
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Mon, 01 Jan 2001 05:00:00 +0000puradmin11545 at http://www.fortnightly.comNews Digesthttp://www.fortnightly.com/fortnightly/2000/06-0/news-digest
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Electric Reliability</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Case No. 2000-095, May 15, 2000 (Ky.P.S.C.).</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 15 2000</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 align="center">News Digest</h1>
<p><center> </center> <center> </center> <br />
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<h3>Electric Reliability</h3>
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<p> <b>Regional Summer Assessments.</b> The North American Electric Reliability Council was set to release its annual summer reliability assessment on May 22, after this issue went to press, but in the meantime, many other regional reliability councils and independent system operators had already issued summer forecasts for generation adequacy and system reliability. </p>
<ul>
<li> <b>New York ISO.</b> Forecasted a peak demand of 30,200 megawatts, representing an increase of 1.7 percent over 1999. It said it had completed a successful auction in the installed capacity market to secure enough generation to satisfy the reserve requirement (18 percent above demand) of 35,636 MW set by the New York State Reliability Council. </li>
<li> <b>ISO New England. </b>Forecasted summer peak demand at 23,250 MW, compared to last year's peak of 22,544 MW, set July 6. Citing new plants coming online, plus favorable nuclear availability, it predicted "an overall improvement" over the last few summers. </li>
<li><b> California ISO.</b> Warned of "slim" power reserves, predicting (with normal weather) a summer peak load on the ISO-controlled grid of 46,250 MW (representing 37,950 MW of internal generation and 8,400 MW of imported power), compared to a 1999 peak of 45,884 MW. </li>
<li> <b>MAIN.</b> Predicted "improved electric reliability" in the Midwest this summer, in light of some 3,000 MW in new generating capacity expected to be online before the high season arrived. MAIN anticipated a summer noncoincident peak demand of 49,615 MW, compared to last year's peak of 49,027 MW. </li>
<li> <b>ECAR.</b> Predicted an 11.2 percent capacity margin in summer 2000, compared with 10.8 percent last summer, due in part to the addition of new generation, reactivation of mothballed generation, and a transfer of load certain obligations from ECAR utilities to entities outside the region. It predicted a net summer peak of 95,765 MW, or about 0.4 percent below last year's record peak demand of 96,149 MW. Nevertheless, it warned that in-service schedules for capacity additions "have the potential for slipping," representing a possible 2.646 MW in shortfall. It added that "under all assumed severe condition scenarios, the ECAR region will have insufficient resources available during the peak summer demand period without a higher level of transmission import." </li>
<li><b> PJM ISO. </b>Forecasted an increase in summer peak load of about 1,400 MW, up to 51,161 for 2000, as compared with 49,751 MW for 1999. It said that no emergency load procedures would be required if anticipated conditions occur, but warned of emergency load controls imposed if "extreme weather" prevails. It added that "May 9, 2000 temperatures reached levels that were last recorded 125 years ago." </li>
</ul>
<p> </p>
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<h3>Mergers &amp; Acquisitions</h3>
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<p> <b>LG&amp;E + PowerGen.</b> Kentucky regulators OK'd the takeover of LG&amp;E Energy Corp. by PowerGen PLC, acknowledging no real merger savings through integration (since PowerGen has "no business presence" in the United States), but citing PowerGen's promise to set up its U.S. headquarters in Louisville- a factor the PSC said would give "top priority" to economic development in Kentucky. </p>
<p><b>NSP + New Century.</b> The North Dakota PSC OK'd the merger of Northern States Power Co. and New Century Energies, finding that energy consumers in the region would benefit through lower gas and electric prices, as well as savings from more options in electric transmission service. </p>
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<p><b>Summer Emergency. </b>The Federal Energy Regulatory Commission on May 17 issued an interim order announcing specific actions aimed at promoting electric reliability this summer, and requesting comments on those actions as well as other steps it can take to increase reliability. The commission acted in response to what it expects will be another summer of potentially high peak demands, and the commissioners used the opportunity to ask Congress for legislation giving FERC authority over reliability. The commission OK'd five measures through September 30: </p>
<ul>
<li> <b>On-Site Generation.</b> Streamlining regulation to foster on-site generation; </li>
<li><b> Demand-Side Management.</b> Facilitating DSM by waiving the prior notice required for filing of new tariffs and encouraging proper calculation of incremental avoided costs; </li>
<li> <b>Transmission Capacity.</b> Encouraging utilities to reassess capacity benefit margin, which represents transmission capacity set aside and reserved for possible use for importing out-of-area resources in the event of outages; and </li>
<li><b> New Ideas.</b> Making FERC staff available to hear practical ideas promoting reliability. </li>
</ul>
<p>Commissioner Curt Hébert wrote a concurring opinion to "lament the lost opportunities of this order." He believes the FERC should have done more earlier to promote building of generation. Commissioner William Massey called for legislation from Congress establishing one set of reliability rules, noting "that the existing scheme of voluntary rules will not work in a competitive market." </p>
<p><b>Purchased Power Costs.</b> The Michigan PSC rejected a motion by a ratepayer coalition that the PSC must disallow recovery of costs incurred by Detroit Edison to acquire operating power reserves, on the theory that the reserves represented excess capacity because the power purchases executed by the utility already inherently were backed by the reserve margins of the sellers of those principal resources. </p>
<p>According to the PSC, that theory would mark a departure from how utilities determine reserve margin. The PSC added, "Indeed, Detroit Edison experienced nondelivery of purchased power on eleven days in 1998 in a total amount of 28,500 [megawatt-hours], which undermines [the theory] regarding the reliability of purchased power." </p>
<p> </p>
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<h3>Transmission &amp; ISOs</h3>
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<p><b>Liability, Penalties, Software.</b> On May 8 various utilities, marketers, and other groups filed over 35 separate briefs in the massive case at the FERC to settle hundreds of unresolved tariff issues involving the California ISO. </p>
<p>Several key issues stood out, including (1) ISO liability for negligence, (2) ISO authority to penalize traders under its market monitoring power, and (3) whether the ISO must disclose algorithms and other details in its proprietary software. </p>
<ul>
<li><b> Liability- Issue 676.</b> Consumer advocates urged the FERC to enforce ISO liability only for gross negligence, as it did in New York. The California ISO urged the same: "The real fear should be that greater liability exposure would likely dissuade transmission owning entities from even joining an RTO." But Dynegy, Enron, PG&amp;E, and various municipal utilities and irrigation districts say because of differences in state law, the FERC should treat the California ISO differently from New York and instead impose liability for ordinary negligence. The California PUC stayed neutral. </li>
<li><b> Penalties- Issue 631.</b> Enron, Dynegy, and the Western Power Trading Forum argue that the ISO must "cleanse" its tariff of certain "offending provisions" that give it the right to play both "judge and jury" and impose sanctions and penalties on market participants when it uncovers "anomalous market behavior." Even though the ISO is not a "market participant" in the traditional sense, the marketers claim that "the ISO operates and controls virtually the entire Ancillary Services market in California." They add, "The ISO has a vested interest in dispelling any allegation that its own negligence could have been a contributing factor in any market anomaly É the ISO will always be biased towards finding parties to blame." </li>
<li><b> Software Disclosure- Issue 537.</b> In October 1997, the FERC directed the ISO to make its computer algorithm publicly available to all market participants, and various marketers and municipal utilities have renewed that demand, calling for FERC to force the ISO to reveal all components, including the computer program, network database, tuning parameters, and "other heuristics" used by the ISO to operate the algorithm. But the ISO maintains that some software is proprietary and disclosure could violate confidentiality obligations under its contract with its outside software vendor. </li>
</ul>
<p><b>Installed Capacity. </b>Citing bidding behavior that looked like price manipulation, ISO New England on May 8 renewed its request to the FERC for authority to terminate its monthly auction market for installed capacity, effective June 1, and for additional guidance on market monitoring and strategies to mitigate market power. The move would leave the ISO with five remaining product markets, each priced on an hourly basis: (1) Energy, (2) 10-Minute Spinning Reserve, (3) 10-Minute Non-Spinning Reserve, (4) Automatic Generation Control, and (5) 30-Minute Operating Reserves. </p>
<p>The ISO also formed a small working group to formulate new models for a capacity reserve market, and said it expected Harvey Reed of Constellation Power Source to chair the group. (Reed also chaired the NEPOOL working group for congestion management and multi-settlement systems.) </p>
<p>The installed capacity requirement forces load-serving entities (LSEs) to maintain ownership or contract rights to capacity to satisfy monthly peak load. The auction allowed bidders to sell the excess or make up any deficiency.In actual bidding, however, the ISO observed anomalies, including an unusual "j-shaped" supply curve, coupled with monthly peaks rising from about $1,000 per megawatt in mid-1999 to as high as $99,999 in mid-winter 1999-2000. </p>
<p>In January, in fact, the ISO found it necessary to reprice one particular bid- which dropped the clearing price from $10,000 per megawatt all the way to zero- after the ISO found that one bid of over 2,000 MW at a price substantially higher than $10,000 had represented over 60 percent of the total non-zero bids for the month. </p>
<p>By contrast, the ISO found that an "active" bilateral market for capacity had emerged in New England, totaling 27,900 MW for March 2000, at contract lengths ranging from one month to a year or longer, which it said exceeded NEPOOL's entire installed capability. But the ISO acknowledged that the bilateral market could represent the "trading and retrading" of the same megawatts, "to a degree not easily possible to quantify." </p>
<p><b>Market Chaos.</b> Alleging that software problems and communications failures were so pervasive that action was needed "to avert a potential disaster this summer," New York State Electric &amp; Gas Co. petitioned the FERC to suspend all market pricing programs operated by the New York ISO for energy, reserve capacity, and ancillary services, for the period June 1 through Oct. 31, and to revert to cost-based pricing. </p>
<p>But cooler heads soon prevailed, and NYSEG agreed to withdraw its request, on consultation with other members of the ISO, including Central Hudson Gas &amp; Electric, Consolidated Edison, Niagara Mohawk, Orange &amp; Rockland, the Long Island Power Authority, and Rochester Gas &amp; Electric. The scaled-back proposal asks the ISO to work out problems internally, and report back to the FERC. </p>
<p><b>Must-Run Plants.</b> The California PUC weighed in on the side of the ISO and a "buyers' coalition" of investor-owned electric utilities in a dispute of whether so-called RMR (reliability must-run) plants should earn a profit when dispatched by the ISO. The dispute involves the private power producers, Southern Energy Delta and Southern Energy Potrero, which own three power plants in the San Francisco "load pocket." </p>
<p>Southern argues that when the ISO dispatches "must-run" plants, it should pay owners a "fixed option payment" (FOP) that compensates them for both incremental operating costs and fixed capital costs. Anything less, says Southern, would amount to a "zero-profit" rate. </p>
<p>The ISO, the utilities, and the FERC trial staff all oppose Southern's argument, pointing out that in most cases Southern does not need to interrupt sales of output from the plants under profitable bilateral contracts in order to comply with the ISO's dispatch orders, so that revenues from bilateral sales are available as a credit against fixed capital costs. Otherwise, say the buyers, Southern would profit from "market power." </p>
<p>Yet Southern countered, "The parties seem to suggest that 'locational rents' are the same as the exercise of market power, which they are not." Southern argued that even the buyers' witness Larry Ruff "conceded at hearing that there was a difference between the ability to capitalize on good locations and the exercise of market power." </p>
<p> </p>
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<h3>State PUCs </h3>
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<p><b>Stranded Costs.</b> In an interim order, the Illinois commission allowed Commonwealth Edison Co. to revise its plan for calculating market prices to set transition charges to recover stranded costs. Com Ed would replace the "neutral fact finder" (NFF) process that had required utilities and marketers to submit summaries of contracts to a committee appointed by the commission. </p>
<p>In his separate concurring opinion, commission chairman Richard L. Mathias said that utilities, consumers and retail suppliers all had questioned the NFF approach- that it could create a "real likelihood" of a "re-monopolization" of the Illinois electric industry. </p>
<p>Com Ed's new plan would calculate peak market prices and forward transaction prices along with bid/ask prices from transactions posted on Altrade and Bloomberg "PowerMatch," two real-time, online electronic power trading exchanges. For off-peak pricing, the utility will use historical day-ahead data published in . To develop hourly prices for each monthly peak- and off-peak period, Com Ed would use locational marginal prices from the 1999 PJM-West Interconnection. The price shape data is then used to translate average block price data into hour-by-hour market values. </p>
<p><b>Electric Choice.</b> Regulators in Virginia OK'd the state's first pilot program (in Richmond, served by Virginia Power) for electric supplier choice, to be available Sept. 1. The program will double in 2001, when another 35,000 customers become eligible in a service area yet to be determined. It was described as "large enough to attract competitive suppliers yet manageable enough to avoid administrative pitfalls." </p>
<p><b>Utility Marketing Affiliates. </b>The Wisconsin PSC ruled that utilities and their affiliates could continue to share resources with all costs fully allocated- except where such sharing is expressly barred, as in natural gas marketing. It found no present need for rules on standards of conduct, but said it would continue to monitor dealings between utilities and affiliates through the existing law, including the state's holding company statute. </p>
<p><b>Medical Equipment.</b> The New York PSC called on utilities to improve service to customers using electricity to run life support equipment (LSE). It said that any customer information system should be capable of identifying customer accounts using LSE in case of outages, voltage instability, or brownout conditions. It recommended that utilities install devices like Central Hudson's "Advisor" or Con Ed's POND. </p>
<p><b>Shopping Credits. </b>To discourage large-volume customers from churning accounts, the Delaware PSC allowed Delaware Electric Co-op Inc. to force customers with demands greater than 300 kilowatts to stay on with the co-op if they return to take bundled electric distribution and commodity service. The PSC set the co-op's shopping credit at 5.197 cents per kilowatt-hour, ignoring the co-op's protest that the figure exceeded Delmarva P&amp;L's shopping credit (4.846 cents) and would offer a "false price signal." </p>
<p><b>Real-time Pricing.</b> Responding to complaints from the Georgia Textile Manufacturers Association and Georgia Industrial Group, the Georgia PSC modified how Georgia Power calculates real-time pricing rates paid by its largest industrial customers, requiring the utility to use the average cost. The change should lower rates by $7 million annually. </p>
<p><b>Shopping Credits.</b> The Midwest Marketers' Coalition opposed the transition plan settlement proposed on April 17 between the Ohio PUC staff and FirstEnergy, claiming it would set an artificially low shopping credit. "In both Massachusetts and Rhode Island, the shopping credits were set below the cost of supplying retail customers," claimed Scott Brown, spokesman for the coalition. "After two years of competition in both states, less than 1 percent of residential customers have switched." </p>
<p><b>Gas Pilot Programs. </b>The Iowa board allowed MidAmerican Energy Co. to extend a gas sales pilot program that offers long-term contracts to smaller customers at a fixed commodity price, despite allegations that the program might hamper the development of gas competition in the state. </p>
<p><b>Natural Gas Rates.</b> The Wyoming PSC allowed Questar Gas Co. to continue to earn an 11.83 percent return on common equity, saying it was reluctant to penalize the company for having filed the rate case voluntarily to reduce rates. </p>
<p><b>Purchased Power.</b> Noting the success of competitive markets in wholesale generation, the Alabama PSC allowed Alabama Public Service Co. to revise its longstanding plan for recovering the fixed costs of electricity supply. The revised plan will set a power rate factor based on the estimated cost of purchased power, excluding any energy charge costs recoverable through the utility's automatic adjustment clause. </p>
<p><b>Affiliate Rules.</b> New Mexico regulators set a code of conduct governing anticompetitive practices in transactions between utilities and affiliates, covering issues ranging from access to transmission and distribution lines and disclosure of customer information. . </p>
<p><b>Supplier Certification.</b> The Texas PUC set a public hearing for June 15 on proposed rules for certifying retail electric providers (REPs) in the newly competitive market scheduled to begin in 2002. Final rules were expected by late July. </p>
<p> </p>
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<h3>Courts </h3>
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<p><b>Union Lockouts.</b> A federal appeals court upheld a ruling by the National Labor Relations Board that Central Illinois Public Service Co. did not commit an unlawful labor practice when it "locked out" union employees who, in lieu of striking, had instituted "inside game" tactics, such as working "to the rule" and refusing voluntary overtime. The court said the utility was entitled to counter such activities. </p>
<p><b>Transmission Pricing.</b> A federal appeals court ruled that an electric utility cannot unilaterally modify the terms of an existing transmission service contract under the doctrine, even though the contract rates are much higher than they would have been if negotiated at a later date under the provider's open access transmission tariff (OATT) filed under FERC Order 888, as long as the buyer only is acquiring "entitlements" power, and not "requirements" service. </p>
<p>The case involved Potomac Electric Power Co., which sought pricing relief on a transmission service contract it had signed with Allegheny Energy back in 1987 for delivery of power imports from Ohio Edison. Potomac Elec. </p>
<p><b>Municipal Franchise Fees.</b> A Texas court ruled that where the PUC had OK'd a rate adjustment clause to allow electric utilities to bill ratepayers for franchise fees concurrently as such fees were paid to municipal governments, without a formal rate case, the utilities could not then call on the PUC to block the municipalities from later assessing retroactive increases in the franchise fees, billed to the utilities on a percentage-of-revenues basis. </p>
<p><b>Clean Air Act.</b> A federal appeals court ruled that it was proper for Congress under the Clean Air Act to delegate authority to Native American nations (with consent from the Environmental Protection Agency) to regulate air quality on all land within tribal reservations, including activities conducted by persons not members of the tribe. Dissenting judge Ginsburg said that the delegation of authority should extend only to the development of tribal implementation plans. </p>
<p> </p>
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<h3>Gas Pipelines</h3>
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<p> <b>Certification.</b> In a decision that drew the wrath of Sen. Frank Murkowski (Rep., Alaska), chairman of the Senate's Committee on Natural Resources, the FERC certified construction of the Independence and SupplyLink gas pipeline projects, but told project sponsors ANR and Transcontinental Gas Pipe Line Co. to first submit proof of contracts in hand with nonaffiliated companies to subscribe at least 35 percent of project capacity. </p>
<p>Murkowski, while pleased with the FERC's project approval, was still unhappy about the evidentiary requirement, and made his feelings known on April 27, two days after the FERC decision was issued, at the hearing where he had invited all four FERC commissioners to comment on pending federal legislation on electricity restructuring. </p>
<p>"I will want an explanation from each of you as to why you are not doing everything you can to get this pipeline built as fast and as cheaply as possible," he warned. </p>
<p>"The commission's actions in the Independence pipeline case seem to indicate that you really don't want this pipeline built." </p>
<p><b>Citygate Constraints.</b> The New York PSC approved a proposal by Rochester Gas and Electric Corp. For easing system constraints on the amount of pipeline nominations that can be made through each of the citygates used to supply RG&amp;E's natural gas distribution system, by requiring gas marketers operating on the company's system to file plans with RG&amp;E stating expected deliveries on each pipeline at different load levels for each month of the upcoming season. </p>
<p>When RG&amp;E must shift load between the two delivery points and additional costs are incurred, it will impose a surcharge on marketers whose deliveries were not within the system constraints, and then pass back the amount collected to its retail customers. </p>
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<p> </p>
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<h3>Power Plants</h3>
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<p><b>Auction Prices. </b>While conceding that the $47.5 million price tag ($119 per kilowatt) was "below outcomes from other generation asset auctions," the New York PSC approved the sale of the 400-MW Albany Steam Station to PSEG Power LLC. </p>
<p>The PSC dismissed allegations by the town of Bethlehem that the price was insufficient, saying that it came as the result of "an extensive marketing effort" to attract "the broadest available range of potential purchasers." The PSC also noted that differences in plant fuels, vintages, regional market prices, and other variables make comparisons among auctions difficult. </p>
<p>"While the Town complains that the station is more valuable than the prices PSEG Power offered, no bidder shared the Town's view," the PSC observed. </p>
<p><b>Generation Divestiture.</b> The Pennsylvania PUC approved the sale by DQE Inc., parent company of Duquesne Light Co., of its seven electric generating plants to Orion Power Holdings of Baltimore for $1.7 billion. As part of the deal, Orion Power Holdings will become the provider of last resort to Duquesne Light customers. </p>
<p><b>Transfers to Affiliates.</b> The Pennsylvania PUC OK'd generation asset transfers to non-regulated affiliates for both Baltimore Gas &amp; Electric Co. and Public Service Electric &amp; Gas Co.: </p>
<ul>
<li> BGE would transfer to Constellation Generation Inc. its 20.99 percent stake in the Keystone Generating Station and its 10.56 percent stake in the Conemaugh Generating Station (all at book value), as well as its partial equity interest in Safe Harbor Power Corp., a hydroelectric power producer. </li>
<li> PSE&amp;G would transfer its interests in Keystone (22.84 percent), Conemaugh (22.5 percent), and the Peach Bottom Atomic Power Station (42.49 percent) to PSE&amp;G Power LLC and its wholly owned subsidiaries, PSEG Fossil and PSEG Nuclear, representing $2.443 billion in assets, to be recorded by the transferee at a book value between $200 million and $400 million. </li>
</ul>
<p><b>Plant Certification.</b> Saying that it must not micromanage electric companies as the industry moves toward a competitive market, the Ohio Power Siting Board issued a certificate of environmental compatibility and public need for construction and operation of the 425-MW West Lorain Combustion Turbine project to Ohio Edison, a wholly owned subsidiary of FirstEnergy. The board said it is up to Ohio Edison to decide whether to curtail load or shut down the project based on operational constraints, especially transmission constraints on the FirstEnergy system. </p>
<p> </p>
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<h3>Studies &amp; Reports</h3>
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<p> <b>Smart Meters.</b> Any move to integrate communications capability into electronic single-phase meters will tilt the market in favor of utility meter manufacturers, according to the consulting firm Frost &amp; Sullivan. </p>
<p>Otherwise, the report predicts a new era of growth for the metering industry, propelled by a growing economy and rising electric demand. </p>
<p>"Tremendous openings exist for vendors that can successfully manufacture and market the next generation of meters," says Frost &amp; Sullivan analyst Patrick Hodges. See <a href="http://www.frost.com">www.frost.com</a>. </p>
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<h3>Business Wire</h3>
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<p><b>CMS Energy Corp.</b> is participating as an asset investor by contributing access to some of its pipeline rights-of-way in a new nationwide broadband telecommunications network being built by Denver-based <b>Aerie Networks. </b>Aerie is planning to complete its 20,000-plus-mile national network in 2003. CMS Energy initially will hold about a 2.5 percent investment in Aerie in exchange for providing access to rights-of-way held by subsidiaries. Aerie also will use the rights-of-way of <b>BP Amoco, Buckeye Partners L.P., Explorer Pipeline Co., Kinder Morgan, Marathon Ashland Pipe Line, National Fuel Gas Supply Corp., Plantation Pipe Line Co., PG&amp;E Corp., Sempra Communications, Sun Pipe Line Co.</b>, and <b>TEPPCO</b>- all equity owners in Aerie. </p>
<p><b>Atlas Technologies LLC</b>, a partially owned subsidiary of Resource America Inc. and provider of web-based billing and customer care solutions to the deregulating energy and converged network services industries, has licensed its Readi Systems suite of software applications to <b>Equitable Resources Inc.</b>, an integrated energy exploration, production, transmission, distribution, and marketing company. Other clients of Atlas Technologies include <b>Dominion Retail Services</b> and <b>FirstEnergy Corp</b>. </p>
<p><b>Avista Corp.</b> has engaged <b>Merrill Lynch</b> as its investment bank and strategic adviser for <b>Avista Labs</b> to assist in evaluating the best ways to maximize the shareholder value inherent in its fuel cell technology. Avista Labs is pioneering the development and commercialization of an integrated, modular proton exchange membrane fuel cell power system targeted for the residential and small commercial markets throughout the world. Merrill Lynch will consider all options, including financial structuring and an initial public offering. </p>
</p>
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Thu, 15 Jun 2000 04:00:00 +0000puradmin10686 at http://www.fortnightly.comPrice Forecasting in Spot Markets: Hidden Risks in Single-Part Biddinghttp://www.fortnightly.com/fortnightly/1998/10-0/price-forecasting-spot-markets-hidden-risks-single-part-bidding
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Edward P. Kahn</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - October 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> The California Power Exchange doesn't solicit separate bids for plant start-up, spinning reserve or base load operation. That can make spark spreads a bit misleading </p>
<p> IT SHOULD COME AS NO SURPRICE THAT THE PROSPECT OF electric competition has created a huge demand for price forecasting services. To their credit, the forecasters have obliged, supplying an abundance of tools and techniques. Do the forecasts serve the needs of those who would use them? </p>
<p> Some might wish to use a price forecast to assign a value to assets. They may wish to buy some of the many generating plants that utilities have decided to sell as part of a settlement to allay stranded costs of alleged market power. Ordinarily, a plant's value reflects the income stream it will produce. Forecasting that income requires an estimate of both market price and the plant's production profile. Moreover, any useful forecast must take volatility into account. It has been argued empirically, in fact, that electricity shows more volatility than other markets, including other energy markets. </p>
<p> Unfortunately, however, real market prices are much more complex than the simple supply-and-demand diagrams of elementary economics texts. Yes, supply and demand remains important, but so are the details of market structure. And in the newly evolving electricity markets, structure is still in question. Valuation becomes especially difficult, for example, when the assets in question are the very units that, when bid into the market, actually help set the prevailing price. To know the price requires, at the very least, that we know the market rules. </p>
<p> The problem begins with the separation of prices from costs. Not all models make this separation. Those that do not typically will set a price at the short-run marginal cost, or SRMC, also known as incremental cost. For competitive electric markets, however, SRMC pricing is incorrect. It is not consistent with the economic reality of the steam-fired generators that set electricity prices most of the time. These generators exhibit average costs that typically run higher than incremental cost. In the world of regulation, SRMC pricing was efficient, because someone (usually the ratepayer) would pick up all those other nonvariable operating costs (perhaps in a fuel adjustment clause). Under competition, however, prices must recover those costs since there won't be a fuel adjustment clause. Consider how this problem is addressed in the pricing rules used in the market for England and Wales. </p>
<p> The market operator in England and Wales takes bids from suppliers that include three different cost elements, representing three types of plant operation: </p>
<p> 1. Base Load. Reflects incremental operating costs only (SMRC), excluding costs for plant start-up or costs to maintain inefficient production at low output levels during no-lead periods. </p>
<p> 2. Peaking Capacity. Reflects start-up costs for immediate dispatch during high-load hours. </p>
<p> 3. Spinning Reserve. Reflects both start-up and no-load costs (SUNL) - i.e., including the costs of inefficient production at low output levels. </p>
<p> The operator then runs a standard unit commitment program to determine which bids minimize total costs. Then the operator must mark up the price for base load capacity that operates during the high demand hours (known in England and Wales as the Table A period) to recover the start-up and no-load costs incurred by all accepted bidders (see Figure 1). </p>
<p> Figure 1 illustrates this fundamental point. This figure is taken from the results of a modern production simulation model. It shows the prices that would result for the same dispatch depending upon which costs need to be recovered. Three cases are shown. One is just SRMC. The second series recovers only start-up costs (in high-load hours). The third recovers both start-up and no-load costs, i.e. the costs of inefficient production at low output levels. </p>
<p> Nevertheless, the E&amp;W market rules have not been universally accepted. In both the California Power Exchange and the Australian electricity markets, the burden of bidding prices that recover start-up and no-load costs falls to bidders. The market operator will not do it for them. This rule is called "single-part bidding," to contrast it with the multiple part bids in the E&amp;W market. If we want to forecast prices in markets that employ single-part bidding, our models must take these rules into account. </p>
<p> Forecasting prices is difficult in markets that employ single-part bidding. Even if a model can allow the user to specify a bid that differs from incremental cost, figuring out what the equilibrium bid strategies will be and simulating them is difficult. Most forecasters don't do this very well, even if they try. Our case study will show us why it is so difficult. </p>
<p> Marginal Plants: </p>
<p> The Option Value in Dispatch </p>
<p> Units that serve intermediate loads (or mid-merit in English terminology) are very different from base load units. The latter can be valued largely on the basis of expected prices. For units that are marginal, the majority of value is option value. That means that the money lies in knowing when to exercise the option to operate. The decision to operate, however, depends upon the distribution of prices - not just on the expected, or average, value of the price. </p>
<p> Table 1 shows two different price structures with the same average, or expected, value, namely $20. The price structure difference between Case 1 and Case 2 is that Case 2 shows a lot of variation; half the time the price is above average and half the time it is below average, while the prices in Case 1 are flat. In Cases 1 and 2 the plant operates all the time, as if it were baseload. In both cases we just break-even. In Cases 3 and 4 we still consider the varying price structure, but we now imagine that the plant is flexible and consider how to operate to maximize profit. In Case 3 we assume perfect flexibility. The plant is operated only when it is profitable. Case 4 represents operating flexibility, so we are only able to turn the plant off half the time that it is unprofitable. These simple examples show that exercising the option to operate or shut down is the key to profitability for mid-merit plant, and that profits can be limited by operating constraints. </p>
<p> Spark Spreads: </p>
<p> What's Hidden by the Averages </p>
<p> Now let's turn to some real valuation experiences. Consider the case of gas-fired steam generation operating in a market based on single-part bidding rules. These units typically have incremental heat rates of 8,000 to 9,000 Btu/kWh, but average heat rates of more than 10,000 Btu/kWh. The reason for the high average heat rates is start-up and no-load costs. The customer who wants to value these units goes to a market price forecaster and says, "Give me some forecasts." Figure 2 is representative of the simulations a customer receives. </p>
<p> These prices are expressed in "spark spread" or market heat rate units, i.e., the electricity price divided by the gas price. The figure shows 24 hourly prices for each day of a "typical week" in a month. Market heat rate units are convenient for profitability analysis because they can be directly related to costs for any gas price. For ease of understanding, I have colored the prices in heat rate bands. (I refer to this scheme as the USA Today weather map of prices, a concept that should be familiar to business travelers.) </p>
<p> Now Figure 2, appears similar to Cases 1 and 2 in Table 1. Both forecasts have the same average value. In Figure 2, the average value is about 8,800 Btu/kWh (see the last cell at the bottom of the "Average" column on the right of each panel). One forecast (Fig. 2, Case 1) exhibits a lot more variance than the other did. I point out this difference to the vendor of the forecasts. He calls me back to say that the "smooth" one is correct (Fig. 2, Case 2) and that the other one is wrong. I thank him for his response. I wonder if he would have bothered to tell me if I hadn't asked. </p>
<p> Next I start to do my valuation. Here I am back to the case depicted in Figure 1, not Table 1. The cost structure of the marginal plants includes the start-up and no load costs (remember average heat rates are higher than incremental rates, a fact that is suppressed in Table 1). I know that the plants that I am valuing really can set the market price sometimes (notice that in the Table 1 examples for Cases 3 and 4 they never set the price). So if I am bidding these plants, and I know I can set the price sometime, I need to get my start-up and no-load costs back or I am losing money. If we were to generalize the Table 1 examples to include start-up and no-load costs, then these would have to be bid in prices. The profits estimated for Cases 3 or 4 would be reduced to account for these costs and the unit would have to bid the start-up, no-load costs in some way vaguely related to Figure 1. The unit probably would end up setting the market price at those bids some of the time. </p>
<p> Now in my real valuation problem, I am starting to get a little uncomfortable. If I have to get the start-up, no-load (SUNL) costs back, so does any other marginal generator. So it doesn't really matter if I actually set the price at a given time, because anybody else bidding a similar plant - and there are many similar plants - has the same problem. I look at my price forecasts again. The one that the vendor tells me is correct never has prices that recover SUNL costs - not for me or for anybody. How can this be correct? </p>
<p> Alternative Techniques: </p>
<p> Promising, but Still Unreliable </p>
<p> The forecaster in the example above has failed what economists call the incentive compatibility test. This is just a fancy way of saying that if the price formation process doesn't recover costs, it is not sustainable, i.e., it is not equilibrium. Now we never really know over what period of time profitability must be achieved. But if I have market price forecasts that aren't consistent with profitability of participants over some period, then capacity will be withdrawn and prices will rise. </p>
<p> This example shows what can happen when the supplier of a price forecast has not thought through the consistency of his story. When the forecaster is using a production simulation model, there is nothing that will force him to have a consistent story. The users bear the risk. </p>
<p> This example is not the end of the story, however. Defining an incentive compatible equilibrium in electricity markets is still a challenge. The dynamics of entry and exit play a role. The profitability criteria for staying in the market are difficult to observe. But at a minimum, the vendors need to provide better disclosure to the users regarding what they have assumed about the profitability of marginal plant. Conversely, the users have a responsibility to be sure that they know what the assumptions behind a price forecast are and that they are reasonable for the purpose at hand. </p>
<p> One could ask if there might be another path. If the production simulation models are so treacherous what other options might there be? Table 2 outlines alternatives. </p>
<p> One modern concept of equilibrium, taking both price and quantity into account, is called the supply function equilibrium. In this formulation, agents in a market have a cost function that they turn into a bid or offer function, which satisfies the equilibrium condition, namely it is a best response to the offer functions of everybody else. Sounds good. Too good to be true, unfortunately. Another more classical approach is the Cournot technique, which uses quantity strategies. These concepts are useful theoretical constructs, but they are very difficult to implement numerically. The efforts to date have been academic exercises that reveal interesting conclusions, but not reliable price forecasts. </p>
<p> For certain short-term trading problems, various statistical techniques can prove very useful and powerful (see Table 2). For products priced in connection with the various geographic centers in the current wholesale market (Palo Verde, COB, Mid-Columbia), statistical models can give both reasonable expected values by estimating the co-integration of price movements and taking account of mean reversion in price. More importantly, these pricing models yield the volatility estimates required for option pricing techniques, such as the famous Black-Scholes model or stochastic dynamic programming. This is an exciting area of current research and there are important techniques available. </p>
<p> In the current state of market development, however, statistical techniques have limited application to asset valuation. Forward curves are unreliable for longer periods of time; volatilities and correlations are unstable. For the brave-hearted, or those who are thoroughly disgusted with fundamental valuation methods, the statistical models are an alternative. Over time, as the markets broaden and liquidity deepens, they will get better. But right now, price forecast users in the asset valuation market are probably stuck with production simulation products. For these users, beware. </p>
<p> Edward P. Kahn is a vice president in the San Francisco office of National Economic Research Associates Inc. Over the previous decade he has held positions as senior scientist in the energy and environment division of the Lawrence Berkeley Laboratory, leader of LBL's utility policy and planning group, and co-director of the Program on Workable Energy Regulation (POWER) at the University of California Energy Institute, also located in Berkeley, Calif. </p>
</p>
<p> 1 See, for example, D. Pilipovic, Energy Risk: Valuing and Managing Energy Derivatives, 1998, for some persuasive evidence. </p>
<p> 2 The best modern papers in this genre are: For Cournot, S. Borenstein and J. Bushnell, "An Empirical Analysis of the Potential for Market Power in California's Electricity Industry," University of California working paper, 1996, and J. Bushnell, "Water and Power: Hydroelectric Resources in the Era of Competition in the Western US," 1998; For SFE, R. Green and D. Newbery, "Competition in the British Electricity Spot Market," Journal of Political Economy, 100(5) 929-953, 1992 and R. Green, "Increasing Competition in the British Electricity Spot Market," Journal of Industrial Economics, 44(2) 205-216, 1996. </p>
<p> 3 See D. Pilipovic, note 1, M. Hsu, "Spark Spread Options are Hot!" The Electricity Journal, v. 11, no. 2 (1998) 6-18 and V. Kaminski, "The Challenge of Pricing and Risk Managing Electricity Derivatives," The US Power Market, 1997. </p>
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Thu, 15 Oct 1998 04:00:00 +0000puradmin9889 at http://www.fortnightly.com